Lonestar Resources US Inc. (Form: 10-12B/A, Received: 06/09/2016 09:54:18)

Presentation of Information

Lonestar Resources US Inc. is filing this registration statement on Form 10 to register its Class A Voting Common Stock, par value $0.001 per share, voluntarily pursuant to Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Lonestar Resources US Inc. was incorporated in the State of Delaware in December 2015 for the purpose of reorganizing the operations of Lonestar Resources Limited, an Australian corporation, into a structure whereby the ultimate parent company of the Lonestar group of companies will be a Delaware corporation. See Item 1 (“Business—Corporate History”)

Prior to the effectiveness of this registration statement, Lonestar Resources US Inc. will acquire all of the issued and outstanding ordinary shares of Lonestar Resources Limited, the current parent company of the Lonestar group of companies, pursuant to a Scheme of Arrangement under Australian law that must be approved by the Federal Court of Australia, which approval is expected to be in June 2016, and by Lonestar Resources Limited’s shareholders at a meeting of shareholders, which approval was obtained in March 2016.

As soon as practicable following completion of the Scheme of Arrangement, we intend to:

· list our Class A Voting Common Stock (referred to in this registration statement as our “common stock”) on The Nasdaq Stock Market LLC (“Nasdaq”); and

· liquidate Lonestar Resources Limited, which is a holding company and itself has no operations (and all its subsidiaries will be subsidiaries of Lonestar Resources US Inc.).

We refer to these transactions as the “Reorganization.” Pursuant to the Reorganization we will issue to the shareholders of Lonestar Resources Limited one share of our common stock for every two ordinary shares of Lonestar Resources Limited that are issued and outstanding. Additionally, we will cancel each of the outstanding options to acquire ordinary shares of Lonestar Resources Limited and issue replacement options representing the right to acquire shares of our common stock on the same one-for-two basis. Prior to the closing of the Reorganization, we will have had no business or operations and following the closing of the Reorganization, the business and operations of Lonestar Resources US Inc. will consist solely of the business and operations of the subsidiaries of Lonestar Resources Limited.

All references in this registration statement regarding acreage as of December 31, 2015 include all leases that were in effect as of such date and exclude leases which were closed after such date or had terms agreed to with a reasonable expectation to close but had not closed by December 31, 2015. Definitions of certain oil and gas terms used in this registration statement are set forth in the “Glossary of selected oil and natural gas terms” beginning on page 3.

Lonestar Resources America, Inc. (“LRAI”) is a subsidiary of Lonestar Resources Limited and has been its U.S. operating company for the Lonestar group of companies since February 2013. LRAI will continue in the role of U.S. operating company for Lonestar Resources US Inc. upon completion of the Reorganization.

Except as otherwise indicated or unless the context otherwise requires, the information included in this registration statement assumes and gives effect to the completion of the Reorganization. Unless the context otherwise requires, references in this registration statement to “Lonestar,” “we,” “us” and “our” refer to Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization.

Currencies

Unless indicated otherwise in this registration statement, all references to $ or dollars refer to U.S. dollars. References to A$ mean the lawful currency of the Commonwealth of Australia.

Cautionary note regarding forward-looking statements

This registration statement contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this registration statement, regarding our strategy, future operations, financial position, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this registration statement, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

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Forward-looking statements may include statements about our:

· discovery and development of crude oil, NGLs and natural gas reserves;

· cash flows and liquidity;

· business and financial strategy, budget, projections and operating results;

· crude oil, NGLs and natural gas realized prices;

· timing and amount of future production of crude oil, NGLs and natural gas;

· availability of drilling and production equipment;

· availability of personnel;

· amount, nature and timing of capital expenditures, including future development costs;

· availability and terms of capital;

· drilling and completion of wells;

· competition;

· marketing of crude oil, NGLs and natural gas;

· timing, location and size of property acquisitions and divestitures;

· costs of exploiting and developing our properties and conducting other operations;

· general economic and business conditions;

· effectiveness of our risk management activities;

· environmental and other liabilities;

· counterparty credit risk;

· governmental regulation and taxation of the crude oil and natural gas industry; and

· our plans, objectives, expectations and intentions.

All forward-looking statements speak only as of the date of this registration statement. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this registration statement are reasonable, we can give no assurance that these plans, objectives, expectations or intentions will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Item 1A (Risk Factors) and Item 2 (Financial Information) and elsewhere in this registration statement.

These factors include risks related to:

· variations in the market demand for, and prices of, crude oil, NGLs and natural gas;

· lack of proved reserves;

· estimates of crude oil, NGLs and natural gas data;

· the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing;

· borrowing capacity under our credit facilities;

· general economic and business conditions;

· failure to realize expected value creation from property acquisitions;

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· uncertainties about our ability to replace reserves and economically develop our reserves;

· risks related to the concentration of our operations;

· drilling results;

· potential financial losses or earnings reductions from our commodity price risk management programs;

· potential adoption of new governmental regulations; and

· our ability to satisfy future cash obligations and environmental costs.

The forward-looking statements relate only to events or information as of the date on which the statements are made in this registration statement. Except as required by law, we undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, after the date on which the statements are made or to reflect the occurrence of unanticipated events.

Implications of being an Emerging Growth Company

As a company with less than $1.0 billion in revenue during our last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). An emerging growth company may avail itself of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. For example, we intend to rely on an exemption from the auditor attestation requirements of Section 404 of the Sarbanes Oxley Act of 2002 (the “Sarbanes Oxley Act”) relating to internal control over financial reporting, and we will not provide such an attestation from our auditors. In addition, we may also take advantage of certain other exemptions available under the JOBS Act, including an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies, an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditors’ report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and exemptions from the requirements of holding advisory “say-on-pay” votes on executive compensation and shareholder advisory votes on golden parachute compensation not previously approved.

We will remain an emerging growth company until the earliest of the following:

· the end of the first fiscal year in which the market value of our common stock held by non-affiliates exceeds $700 million as of the end of the second quarter of such fiscal year;

· the end of the first fiscal year in which we have total annual gross revenues of at least $1 billion; or

· the date on which we have issued more than $1 billion in non convertible debt securities in any rolling three year period.

Once we cease to be an emerging growth company, we will not be entitled to the exemptions provided for by the JOBS Act.

Glossary of selected oil and natural gas terms

We are in the business of exploring for and producing oil and natural gas. Oil and natural gas exploration is a specialized industry. Many of the terms used to describe our business are unique to the oil and natural gas industry. The following is a description of the meanings of some of the oil and natural gas industry terms used in this document.

3-D seismic data. Geophysical data that depicts the subsurface strata in three dimensions.

Analogous reservoir. Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

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Basin. A large natural depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of oil or other liquid hydrocarbons.

Boe. Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d. Barrels of oil equivalent per day.

Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Deterministic method. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas.

Development well. A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

Dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Economically producible or viable . The term economically producible or economically viable, as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and natural gas producing activities.

Estimated ultimate recovery . Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploitation. Optimizing oil and natural gas production from producing properties or establishing additional reserves in producing areas through additional drilling or the application of new technology.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells . The total acres or wells, as the case may be, in which a working interest is owned.

Held by production acreage. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

Horizontal well. A well in which a portion of the well has been drilled horizontally within a productive or potentially productive formation. This operation usually results in the ability of the well to produce higher volumes than a vertical well drilled in the same formation.

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Hydraulic fracturing or fracking . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

Injection. A well which is used to place liquids or natural gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.

MBoe. Thousand barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

MMBoe. Million barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Mcf. Thousand cubic feet of natural gas.

MMBtu. Million British Thermal Units.

Natural gas liquids or NGL. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be. An owner who has 50% interest in 100 acres owns 50 net acres.

NYMEX. New York Mercantile Exchange.

Possible Reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed proved plus probable plus possible reserves estimates.

Probable Reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Probabilistic method. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

Productive well. A well that is producing or is capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved oil and natural gas reserves or Proved reserves . Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of

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whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following: (i) the area identified by drilling and limited by fluid contacts, if any; and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and natural gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the 12-month first day of the month historical average price during the twelve- month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of- the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves or PUD . Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

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Reserves. Reserves are estimated remaining quantities of oil, and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil, and natural gas or related substances to market and all permits and financing required to implement the project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resource play. These plays develop over long periods of time, well- by-well, in large-scale operations. They typically have lower than average long-term decline rates and lower geological and commercial development risk than conventional plays. Unlike most conventional exploration and development, resource plays are relatively predictable in timing, costs, production rates and reserve additions which can provide steady long-term reserves and production growth.

Resources. Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

Stratigraphic horizon. A sealed geologic interval capable of retaining hydrocarbons that was formed by changes in rock type or pinch-outs, unconformities, or sedimentary features such as reefs.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether or not such acreage contains proved reserves.

Undeveloped oil and natural gas reserves or Undeveloped reserves . Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

WTI. West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an API gravity between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

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Item 1. Business.

Overview

We are an independent oil and natural gas company, focused on the acquisition, development and production of unconventional oil, NGLs and natural gas properties in the Eagle Ford Shale in Texas, where we have accumulated approximately 37,004 gross (32,564 net) acres in what we believe to be the formation’s crude oil and condensate windows. We also hold a portfolio of conventional, long lived, crude oil weighted onshore assets in Texas and are inviting farm-in partners to undertake exploratory drilling on approximately 44,084 gross (28,655 net) acres in the Poplar West area of the Bakken Three Forks formation in Roosevelt County, Montana.

We plan to invest substantially all of our 2016 capital budget in the horizontal development of our Eagle Ford Shale properties, on which we plan to allocate between $35 million and $45 million to Eagle Ford Shale drilling and completion activities. We believe our management team’s extensive experience in acquiring and operating oil and natural gas properties will assist us in the development, completion and growth of these properties.

Our Business Strategies

Our primary business objective is to increase reserves, production and cash flows at what we consider to be attractive rates of return on invested capital. We are focused on exploiting long-lived, unconventional oil, NGLs and natural gas reserves from the crude oil window of the Eagle Ford Shale. Key elements of our business strategy include:

Develop our Eagle Ford Shale leasehold positions. We intend to drill and develop our acreage position to maximize the value of our resource potential while maintaining financial flexibility. Through the conversion of our resource base to developed reserves, we will seek to increase our reserves, production and cash flow. As of December 31, 2015, we were producing from 63 gross (57 net) Eagle Ford wells and have 164 gross (148 net) engineered locations for potential future horizontal drilling in our Eagle Ford Shale acreage that will be our primary targets in the near term.

Leverage our extensive operational expertise and concentration of our operating areas to reduce costs and enhance returns. We are focused on continuously improving our operating measures. We intend to leverage the magnitude and concentration of our acreage within the Eagle Ford Shale, as well as our experience within our areas of operation to capture economies of scale, including by employing multiple-well pad drilling, and utilizing centralized production and fluid handling facilities. Our team has significant operating experience, and it regularly evaluates our operating measures against those of other operators in our area in order to improve our performance and identify additional opportunities to optimize our drilling and completion techniques and make informed decisions about our capital expenditure program and drilling activity.

Execute organic leasing and strategic acquisitions in the Eagle Ford Shale. We have more than tripled our Eagle Ford Shale holdings from 9,923 net acres as of December 31, 2013 to 33,951 net acres as of December 31, 2015. We have successfully increased our production, reserves and drilling locations through organic leasing, selective acquisitions and farm-ins, and we intend to continue to evaluate acquisition and leasing opportunities that meet our strategic and financial objectives. We focus our acquisition activity where we believe our operational expertise provides the opportunity for meaningful incremental value creation, where our operational methods are relevant and where we would serve as operator following the acquisition. Further, we continue to seek new leasing and farm-in opportunities to expand our acreage position and complement our existing drilling inventory, as we believe that targeted organic leasing around our existing acreage provides the ability for greater returns due to cost and operating synergies in neighboring areas of operation.

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Maintain operational control over our drilling and completion operations. We operate 100% of the Eagle Ford Shale wells in which we have a working interest and intend to maintain a high degree of operational control over substantially all of our producing locations. Moreover, we hold an average working interest of 94% in our Eagle Ford Shale leasehold. We believe this strategy allows us to manage the timing and levels of our development spending, while controlling the techniques used to drill and complete wells, as well as overall well costs and operating costs. We expect to operate the drilling and completion phase on approximately 100% of our identified drilling locations. Approximately 54% of our existing Eagle Ford net acreage is held by production, and we anticipate that we will further increase the percentage of our Eagle Ford acreage that is held by production through our drilling program. Accordingly, we do not have to expend significant capital in 2016 to hold acreage in our portfolio. We believe that continuing to exercise a high degree of control over our acreage position will provide us with flexibility to manage our drilling program and optimize our returns and profitability.

Maintain financial liquidity and flexibility. We intend to use cash on hand, borrowings from our revolving credit facility, combined with our cash flow from operations, to continue executing a capital expenditure program that we believe will result in steady growth of production, cash flow and proved reserves. Furthermore, we intend to continue executing hedging transactions from currently producing wells, to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in oil, NGLs and natural gas prices. As of December 31, 2015, we had in place hedges covering approximately 2,276 Bo/d for calendar year 2016 at an average price of approximately $77.15 per barrel. We believe that these hedges insulate us from oil price volatility on approximately 54% of our expected crude oil production in 2016. Since December 31, 2015, we have entered into additional WTI crude oil swaps covering a total of 174,550 barrels for the period of May 2016 through December 2016. The addition of these swaps increased the company’s crude oil swap coverage to a total of approximately 2,847 barrels of oil per day, or approximately 70% of our expected oil production for 2016 at an average swap price of $68.69 per barrel. We have also entered into three-way collars covering 1,000 Bo/d for calendar year 2017, which provide an effective floor of $55.25 per barrel with WTI prices between $40.00 per barrel and $60.00 per barrel, but also gives upside to $80.25 per barrel.

Optimize our current position and maximize cost-saving opportunities in response to oil price declines. We have moderated our drilling activity plans for 2015 and 2016 in response to oil price declines that began in late 2014, and our revised plan is to complete 10 (gross and net) wells in 2016. We believe that we are in a good position to be flexible due to our financial position, a $100 million joint development agreement entered into with IOG Capital L.P. (“IOG”) in July 2015, the absence of material drilling obligations and strong operational capabilities. We estimate production will increase from 6,407 Boe/d in 2015 to between 6,400 to 7,000 Boe/d in 2016.

Competitive Strengths

We possess a number of competitive strengths that we believe will allow us to successfully execute our business strategy:

Strategic geographic focus in one of North America’s leading unconventional oil plays. We have assembled a leasehold position of approximately 33,951 net acres in the Eagle Ford Shale as of December 31, 2015. We believe this unconventional oil and natural gas formation has one of the highest rates of return among such formations in North America. In addition to leveraging our technical expertise in our project areas, our geographically-concentrated acreage position allows us to establish economies of scale with respect to drilling, production, operating and administrative costs. Based on our drilling and production results and well-established offset operator activity in and

Experienced management team. Our top eight executives average 30 years of industry experience. We have assembled what we believe to be a strong technical staff of geoscientists, field operations managers and engineers with significant experience drilling horizontal wells and with fracture stimulation of unconventional formations, which has resulted in a successful track record of reserve and production growth. In addition, our management team has extensive expertise and operational experience in the oil and natural gas industry with a proven track record of successfully negotiating, executing and integrating acquisitions. Members of our management team have previously held positions with major and large independent oil and natural gas companies, including Encore Acquisition Company, Denbury Resources, Petrohawk Energy, Burlington Resources, ExxonMobil, Pioneer Natural Resources and Kerr-McGee.

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Demonstrated ability to increase acreage position and drive growth of oil production and reserves. In recent years, we have increased our Eagle Ford Shale net acres by over eight times from 3,710 net acres to 33,951 net acres as of December 31, 2015. We placed 16 gross (13 net) Eagle Ford Shale wells onstream during 2015 and had a total of 63 gross (57 net) producing wells in the Eagle Ford, as of December 31, 2015. The resulting production rates achieved by this program increased Eagle Ford sales volumes by approximately 43% over 2014. Our average total production for 2015 was 6,407 Boe/d, of which 90% was from the Eagle Ford Shale. Moreover, between December 31, 2014 and December 31, 2015, our total proved reserves increased by approximately 30% from 31.0 MMBoe to 40.2 MMBoe, and our proved developed reserves increased by approximately 8% from 12.3 MMBoe to 13.3 MMBoe. Our three-year average reserve replacement ratio is approximately 400%, which we believe demonstrates our ability to grow reserves year over year. We believe the location and concentration of our project areas within the Eagle Ford provide us an opportunity to continue to increase production, lower costs and further delineate our proved reserves.

Multi-year drilling inventory in existing and emerging resource plays. We have 164 gross (148 net) engineered horizontal drilling locations on 30,581 of our 33,951 net acres in the Eagle Ford Shale. As of December 31, 2015, these engineered drilling locations included 58 gross (56 net) locations to which we have assigned proved undeveloped reserves. We have identified 10 gross (10 net) engineered locations in the Eagle Ford Shale that we expect to drill in 2016, the completion of which would represent approximately 6% of our gross engineered drilling locations in the Eagle Ford Shale at December 31, 2015. We have 7,661 additional net acres in the Eagle Ford Shale with surrounding industry activity to which we have not assigned locations. We believe our acreage is prospective for additional locations and plan to continue evaluating this acreage and monitoring industry activity in order to maximize our efficiency in developing this acreage. Furthermore, we expect to identify and develop additional locations across our portfolio as we evaluate downspacing in the Eagle Ford Shale and accessing other stratigraphic horizons that lie above and below the Eagle Ford Shale, such as the Austin Chalk, Buda, Georgetown, Woodbine and Wilcox formations. Additionally, we and our partners are currently processing 3-D seismic data on our assets in the West Poplar area of the Bakken-Three Forks trend of the Williston Basin and will subsequently interpret it to determine future exploration and development opportunities on this acreage. We believe our multi-year, engineered drilling inventory and exploration portfolio will provide near-term growth in our production and reserves and highlight the long-term resource potential across our asset base.

Oil-weighted reserves and production. Our net proved reserves at December 31, 2015 were comprised of approximately 60% oil, and our net average daily production for the year ended December 31, 2015 and 2014 was comprised of 66% oil and 73% oil, respectively. Given the current commodity price environment and resulting disparity between oil and natural gas prices on a Boe basis, we believe our high percentage of oil reserves, compared to our overall reserve base, is a key strength.

Low field operating expenses. Even in light of recent declines in oil prices, we expect to generate sufficient cash margins on our Eagle Ford Shale business due to our low cash operating costs. For the year ended December 31, 2015, our total field operating expenses (including lease operating expenses and production taxes) totalled $10.12 per Boe around our project areas, we believe there are relatively low geologic risks and repeatable drilling opportunities across our core operating areas in the Eagle Ford Shale where we have devoted almost all of our 2015 drilling capital budget.

Hedging position. As of December 31, 2015, we had in place hedges covering approximately 2,276 Bo/d for calendar year 2016 at an average price of approximately $77.15 per barrel. We believe that these hedges insulate us from oil price volatility on approximately 54% of our expected crude oil production in 2016. Since December 31, 2015, we have entered into additional WTI crude oil swaps covering a total of 174,550 barrels for the period of May 2016 through December 2016. The addition of these swaps increased the company’s crude oil swap coverage to a total of approximately 2,847 barrels of oil per day, or approximately 70% of our expected oil production for 2016 at an average swap price of $68.69 per barrel. We have also entered into three-way collars covering 1,000 Bo/d for calendar year 2017, which provide an effective floor of $55.25 per barrel with WTI prices between $40.00 per barrel and $60.00 per barrel, but also gives upside to $80.25 per barrel.

Historically, our preference has been to utilize swaps and collars, both of which are costless and do not burden our liquidity. We regularly assess the futures markets for opportunities to enter into additional hedging contracts. Generally, we have entered into additional hedges when we believe that they are additive to our borrowing base and/or lock-in rates of return which exceed our hurdle rates. When such market conditions present themselves, we anticipate entering into additional hedging transactions. Currently, we have swaps covering approximately 54% of our 2016 expected crude oil volumes and costless collars covering approximately 20% of our 2017 expected crude oil volumes, leaving us substantial capacity to enter into additional hedging contracts if market conditions meet our criterion.

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not intended to represent the current market value of our estimated oil and natural gas reserves. We do not currently have proved reserves on our acreage in the West Poplar Area of the Bakken-Three Forks trend in Montana. Reserves reported below for our Eagle Ford shale assets are owned by our subsidiary Lonestar Resources, Inc., and reserves reported below for our conventional assets are owned by our subsidiary Amadeus Petroleum, Inc.

	As of December 31,
	2015		2014		2013
Estimated Proved Reserves (1)
Eagle Ford Shale:
Oil (MBbls)	21,789		20,861		10,490
NGLs (MBbls)	7,154		3,044		1,841
Natural Gas (MMcf)	54,395		21,528		12,651
Total Eagle Ford Shale (MBoe)(2)	38,009		27,493		14,440
Conventional Assets:
Oil (MBbls)	1,727		2,749		2,994
NGLs (MBbls)	35		—		—
Natural Gas (MMcf)	2,586		4,441		4,722
Total Conventional Assets (MBoe)(2)	2,192		3,490		3,781
Total Estimated Proved Reserves (MBoe)(2)	40,201		30,983		18,220
Estimated Proved Developed Reserves
Eagle Ford Shale:
Oil (MBbls)	6,596		7,044		3,801
NGLs (MBbls)	2,020		1,212		639
Natural Gas (MMcf)	14,948		8,360		4,355
Total Eagle Ford Shale (MBoe)(2)	11,107		9,649		5,166
Conventional Assets:
Oil (MBbls)	1,727		2,140		2,394
NGLs (MBbls)	35		—		—
Natural Gas (MMcf)	2,586		3,631		3,933
Total Conventional Assets (MBoe)(2)	2,193		2,745		3,049
Total Estimated Proved Developed Reserves (MBoe)(2)	13,300		12,395		8,215
Estimated Proved Undeveloped Reserves
Eagle Ford Shale:
Oil (MBbls)	15,193		13,817		6,688
NGLs (MBbls)	5,134		1,833		1,203
Natural Gas (MMcf)	39,447		13,167		8,296
Total Eagle Ford Shale (MBoe)(2)	26,902		17,844		9,274
Conventional Assets:
Oil (MBbls)	—		609		600
NGLs (MBbls)	—		—		—
Natural Gas (MMcf)	—		810		789
Total Conventional Assets (MBoe)(2)	—		744		731
Total Estimated Proved Undeveloped Reserves (MBoe)(2)	26,902		18,588		10,005
PV-10 (millions)(3)	$	294.3	$	705.8	$	418.7
Standardized Measure (millions)(4)	$	268.4	$	549.0	$	302.8
Oil and Gas Prices Used (1) :
Oil — NYMEX-WTI per Bbl	50.28		$	94.99	$	96.94
Natural Gas — NYMEX-Henry Hub per MMBtu	2.59		$	4.35	$	3.67

(1) Our estimated net proved reserves and related Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our properties. The prices are based on the average prices during the 12-month period prior to the ending date of the period covered, determined as the unweighted arithmetic average of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual arrangements, and are adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead.

(2) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an industry-standard approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.

(3) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 differs from the Standardized Measure because it does not include the effect of future income taxes. See below for a reconciliation of our Standardized Measure to PV-10.

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PV-10

Certain of our oil and natural gas reserve disclosures included in this registration statement are presented on a PV-10 basis. PV-10 is the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows (the “Standardized Measure”). We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of a pre-tax PV-10 value provides greater comparability when evaluating oil and gas companies. The PV-10 value is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. The definition of PV-10 value as defined in “Item 1. Business—Glossary of Certain Industry Terms” may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value as defined may not be comparable to similar measures provided by other companies.

The following table provides a reconciliation of PV-10 to the Standardized Measure:

	As of December 31,
($ in millions)	2015		2014		2013
PV-10:
Eagle Ford	$	275.9	$	643.6	$	344.5
Conventional Assets	18.4		62.2		74.2
Total PV-10	294.3			705.8		418.7
Future Income Taxes:
Eagle Ford	25.8		143.1		94.8
Conventional Assets	.1		13.7		21.1
Total Future Income Taxes	25.9		156.8		115.9
Standardized Measure of Discounted Future Net Cash Flows:
Eagle Ford	250.1		500.5		249.7
Conventional Assets	18.3		48.5		53.1
Total Standardized Measure of Discounted Future Net Cash Flows	$	268.4	$	549.0	$	302.8

Reconciliation of Proved Reserves

Our proved developed oil and natural gas reserves increased 7% from 12.4 million BOE at December 31, 2014 to 13.3 million BOE at December 31, 2015 due to drilling delineation and development wells on our existing properties, and augmented by drilling on new properties which were acquired via farm-ins during the year. During the year, we converted 3.4 million BOE of Proved Undeveloped reserves to the Proved Developed Producing category and added 2.4 million BOE through drilling on new properties, while producing 2.4 million BOE during the year ended December 31, 2015. Our proved developed oil and natural gas reserves experienced negative revisions of 2.6 million BOE, largely as a result of lower oil and gas prices.

	Proved Developed Reserves
	Eagle Ford		Conventional		Total
	MBOE		MBOE		BOE
As of Dec, 31 2014	9,650		2,745		12,395
Extensions and Discoveries	2,401		0		2,401
Purchases of minerals in place	21		0		21
Revisions of prior estimates	(2,286	)	(315	)	(2,601	)
Production	(2,112	)	(237	)	(2,350	)
Conversion of proved undeveloped to proved developed	3,434		0		3,434
As of Dec, 31 2015	11,108		2,192		13,300

Our proved undeveloped oil and natural gas reserves increased 45% from 18.6 million BOE at December 31, 2014 to 26.9 million BOE at December 31, 2015 due to drilling delineation and development wells on our existing properties, and augmented by drilling on new properties which were acquired via farm-ins during the year. In the Eagle Ford Shale, through farm-ins, lease acquisitions and reserve purchases, we added 36 gross PUD locations in 2015 with reserves totaling 16.4 million BOE. Our proved undeveloped oil and natural gas reserves experienced negative revisions of 4.6 million BOE as a result of lower oil and gas prices. Included in the negative price revisions were 3.9 million BOE in the Eagle Ford Shale, associated with a combination of price-related revisions to PUD’s which remained in our reserves at December 31, 2015 as well as certain PUD locations that were removed as a result of lower prices. Additionally, all of the Company’s 0.7 million BOE’s of PUD’s associated with its Conventional assets were removed as a result of lower prices.

At December 31, 2015, we did not have any reserves that have remained undeveloped for five or more years since the date of their initial booking and all PUD drilling locations are scheduled to be converted within five years of their initial booking.

	Proved Undeveloped Reserves
	Eagle Ford		Conventional		Total
	MBOE		MBOE		BOE
As of Dec, 31 2014	17,844		744		18,588
Extensions and Discoveries	14,149		0		14,149
Purchases of minerals in place	2,209		0		2,209
Revisions of prior estimates	(3,865	)	(744	)	(4,610	)
Conversion of proved undeveloped to proved developed	(3,434	)	0		(3,434	)
As of Dec, 31 2015	26,902		0		26,902

Development of Proved Undeveloped Reserves

At December 31, 2015, our proved undeveloped reserves were approximately 26,902 MBoe, an increase of approximately 8,314 MBoe over our December 31, 2014 estimated proved undeveloped reserves of approximately 18,588 MBoe. In 2015, we added net proved undeveloped reserves of 14,149 MBoe as a result of drilling and completion activities and 2,209 MBoe as a result of the acquisition of proved undeveloped reserves. During 2015, approximately 3,434 MBoe of proved undeveloped reserves as of December 31, 2014 were converted to proved developed reserves as a result of drilling and completion activities during the year, and 4,610 MBoe of reserves were subtracted from our proved undeveloped reserves as a result of revisions in estimates from 2014. During the year ended December 31, 2015, we incurred capital expenditures of approximately $49.4 million to convert these proved undeveloped reserves as of December 31, 2014 to proved developed reserves.

At December 31, 2014, our proved undeveloped reserves were approximately 18,588 MBoe, an increase of approximately 8,583 MBoe over our December 31, 2013 estimated proved undeveloped reserves of approximately 10,005 MBoe. In 2014, we added net proved undeveloped reserves of 1,904 MBoe as a result of drilling and completion activities and 7,916 MBoe as a result of the acquisition of proved undeveloped reserves. During 2014, approximately 1,576 MBoe of proved undeveloped reserves as of December 31, 2013 were converted to proved developed reserves as a result of drilling and completion activities during the year, and 339 MBoe of reserves were added to proved undeveloped reserves as a result of revisions in estimates from 2013. During the year ended December 31, 2014, we incurred capital expenditures of approximately $34.2 million to convert these proved undeveloped reserves as of December 31, 2013 to proved developed reserves.

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Qualifications of Responsible Technical Persons

Internal Company Person. Thomas H. Olle, our Senior Vice President- Operations, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. Mr. Olle is also responsible for our interactions with and oversight of our independent third-party reserve engineers. Mr. Olle has more than 35 years of industry experience, with expertise in reservoir management and project development across a broad range of reservoir types. Mr. Olle previously held senior positions at Encore Acquisition Corp. and Burlington Resources. He holds a Bachelor of Science degree in Mechanical Engineering with Highest Honors from the University of Texas at Austin and is a member of the Society of Petroleum Engineers.

Independent Reserve Engineers. W.D. Von Gonten & Co. is an independent petroleum engineering and geological services firm. No director, officer or key employee of W.D. Von Gonten & Co. has any financial ownership in Lonestar. W.D. Von Gonten & Co.’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and W.D. Von Gonten & Co. has not performed other work for us or our affiliates that would affect its objectivity. The engineering information presented in W.D. Von Gonten & Co.’s reports was overseen by William D. Von Gonten, Jr., P.E. Mr. Von Gonten is an experienced reservoir engineer having been a practicing petroleum engineer since 1990. He has a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and is a licensed Professional Engineer in the State of Texas.

LaRoche Petroleum Consultants, Ltd. is an independent petroleum engineering and consulting firm. No director, officer or key employee of LaRoche Petroleum Consultants, Ltd. has any financial ownership in Lonestar. LaRoche Petroleum Consultants, Ltd.’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and LaRoche Petroleum Consultants, Ltd. has not performed other work for us or our affiliates that would affect its objectivity. The engineering information presented in LaRoche Petroleum Consultants, Ltd.’s report was overseen by William M. Kazmann. Mr. Kazmann is an experienced reservoir engineer having been a practicing petroleum engineer since 1974. He has been with LaRoche Petroleum Consultants, Ltd. for more than 17 years, where he is President and Senior Partner. He has a Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Texas at Austin and is a licensed Professional Engineer in the State of Texas.

Technology Used To Establish Proved Reserves

Our independent reserve engineers follow SEC rules and definitions in preparing their reserve estimates. Under SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geological, geochemical and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our

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reserves include electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well-test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Internal Controls Over Reserves Estimation Process

Our estimated reserves at December 31, 2014 and 2013 for the Eagle Ford Shale properties were prepared by W.D. Von Gonten & Co., independent reserve engineers. Our estimated reserves at December 31, 2014 and 2013 for our conventional long-lived, crude oil-weighted onshore assets were prepared by LaRoche Petroleum Consultants, Ltd., independent reserve engineers. We expect to continue to have our reserve estimates prepared annually by our independent reserve engineers. Our internal professional staff works closely with W.D. Von Gonten & Co. and with LaRoche Petroleum Consultants, Ltd. to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation processes. All of the production, expense and well-ownership information, maintained in our secure reserve engineering database, is provided to our independent engineers. In addition, we provide such engineers other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures, pricing differentials and relevant economic criteria, including lease operating statements. We make all requested information, as well as our pertinent personnel, available to our independent engineers in connection with their evaluation of our reserves. Year-end reserve estimates are reviewed by our Senior Vice President-Operations, our Chief Executive Officer and other senior management, and revisions are communicated to our board of directors.

Production, Revenues and Price History

The following table sets forth information regarding gross wells brought online during the period, combined net production of oil, NGLs and natural gas and certain price and cost information attributable to our properties, for the years ended December 31, 2015, 2014 and 2013.

	Year ended December 31,
	2015		2014		2013
Gross Wells Drilled by Area: (1)
Western Eagle Ford	13		8		10
Central Eagle Ford	3		9		2
Eastern Eagle Ford	—		5		—
Total Eagle Ford	16		22		12
Conventional	—		—		—
Production
Oil (Bbls/day):
Western Eagle Ford	2,384		1,817		1,477
Central Eagle Ford	943		623		—
Eastern Eagle Ford	516		393		—
Total Eagle Ford	3,843		2,833		1,477
Conventional Assets	373		434		547
Total Oil	4,216		3,267		2,024
Natural gas liquids (Bbls/day):
Western Eagle Ford	795		399		265
Central Eagle Ford	35		—		—
Eastern Eagle Ford	33		24		—
Total Eagle Ford	864		423		265
Conventional Assets	13		13		3
Total NGLs	877		436		268
Natural Gas (Mcf/day):
Western Eagle Ford	5,873		3,149		1,897
Central Eagle Ford	175		2		—
Eastern Eagle Ford	176		126		—
Total Eagle Ford	6,224		3,277		1,897
Conventional Assets	1,663		1,387		1,248
Barnett Shale	—		—		1,224
Total Natural Gas	7,887		4,664		4,369
Average Daily Production (Boe/d)	6,407		4,480		3,020
Average Daily Sales Price:
Oil ($/Bbl)	$	45.93	$	87.41	$	96.95
NGLs ($/Bbl)	12.66		29.26		29.78
Natural Gas ($/Mcf)	2.39		4.50		4.15
Average Unit Cost ($/Boe):
Lease operating expenses(2)	$	7.99	$	9.60	$	12.54
Production taxes	2.13		4.36		4.65
Depreciation, depletion and amortization	25.16		24.91		25.66

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(1) Includes wells placed online during the period shown.

(2) Includes $0.6 million in 2013 associated with P&A expense related to actions mandated by regulatory agencies.

Drilling Activities

The following table sets forth information with respect to wells drilled and completed during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

	Year ended December 31,
	2015		2014		2013
	Gross	Net	Gross	Net	Gross	Net
Development Wells:
Productive	16	13	21	19	12	10
Dry	—	—	—	—	—	—
Exploratory Wells:
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total Wells:
Productive	16	13	21	19	12	10
Dry			—	—	—	—

The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2015. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells.

	Productive Wells (Oil)		Productive Wells (Gas)		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Eagle Ford:
Operated by us	59.0	54.5	4.0	2.3	63.0	56.8
Non-operated	—	—	—	—	—	—
Total Eagle Ford	59.0	54.5	4.0	2.3	63.0	56.8
Conventional:
Operated by us	241.0	187.0	23.0	19.8	264.0	206.8
Non-operated	15.0	3.8	—	—	15.0	3.8
Total Conventional	256.0	190.8	23	19.8	279.0	210.6

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Developed and Undeveloped Acreage

The following table sets forth information relating to our leasehold acreage in the Eagle Ford and the Bakken-Three Forks Trend (West Poplar). As of December 31, 2015, approximately 54% of our net Eagle Ford acreage was held by production.

	As of December 31, 2015
	Developed Acreage		Undeveloped Acreage		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Western Eagle Ford	4,224	4,067	10,216	9,366	14,440	13,433
Central Eagle Ford	2,899	2,414	8,767	8,767	11,666	11,181
Eastern Eagle Ford	1,065	1,029	11,071	8,308	12,136	9,337
Total Eagle Ford	8,187	7,510	30,055	26,441	38,242	33,951
West Poplar	—	—	44,084	28,655	44,084	28,655
Total	8,187	7,510	74,139	55,096	82,326	62,606

As of December, 2015, we had leases across the Eagle Ford Shale representing 3,011 net acres expiring in 2016, 4,519 net acres expiring in 2017 and 563 net acres expiring in 2018 and beyond. We anticipate that our current and future drilling plans together with selected lease extensions will address a significant portion of our leases expiring in the Eagle Ford Shale in 2016. Our 28,655 net acres in the West Poplar project are subject to leases expiring in 2016, and we have an option to renew those leases for another three to five years at prices ranging from $125 to $300 per acre. With respect to West Poplar, we recently received approval of the Stone Turtle Indian Exploratory unit by the Bureau of Land Management and Bureau of Indian Affairs that establishes a 5-year primary term on all leasehold in the unit, in exchange for drilling activity. This approval opens the door for development of the block either by Lonestar or a farm-in partner. To date, we have only drilled one vertical exploratory well in our West Poplar leasehold.

Operations

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties range from 19.0% to 25.0% resulting in a net revenue interest to us ranging from 75.0% to 81.0%.

Marketing and Major Customers

For the year ended December 31, 2015, purchases by our largest four customers accounted for 38%, 20%, 16%, and 11% respectively, of our total sales revenues.

Since the oil and natural gas that we sell are commodities for which there are a large number of potential buyers and because of the adequacy of the infrastructure to transport oil and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time.

Title to Properties

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain an additional title opinion or conduct a review to ensure all title is current relative to previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

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We typically conduct title review of all acquired properties, regardless of whether they have proved reserves. Prior to the commencement of drilling operations on any property, we update our title examination and perform curative work with respect to significant defects or customary assignments, if any. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, resulting in seasonal fluctuations in the price we receive for our natural gas production. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation.

Competition

We operate in a highly competitive environment for leasing and acquiring properties and in securing trained personnel. Our competitors include major and independent oil and natural gas companies that operate in our project areas. These competitors include, but are not limited to, Anadarko Petroleum Corporation, Chesapeake Energy Corporation, EP Energy Corporation, Carrizo Oil & Gas, Inc., Halcón Resources Corporation, Hunt Oil Company, Marathon Oil Corporation, Newfield Exploration Company and Stonegate Production Company. Many of our competitors have substantially greater financial, technical and personnel resources than we do, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive crude oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry.

We are also affected by the competition for and the availability of equipment, including drilling rigs and completion equipment. We are unable to predict when, or if, shortages of such equipment may occur or how they would affect our development and exploitation programs.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, crude oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for crude oil and natural gas production have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the

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method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the rateability or fair apportionment of production from fields and individual wells.

The regulatory burden on the industry increases the cost of doing business and affects profitability. Failure to comply with applicable laws and regulations can result in substantial penalties. Furthermore, such laws and regulations are frequently amended or reinterpreted, and new proposals that affect the crude oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We believe that we are in substantial compliance with all applicable laws and regulations and that our continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. Nor are we currently aware of any specific pending legislation or regulation that is reasonably likely to be enacted, or for which we cannot predict the likelihood of enactment, and that is reasonably likely to have a material effect on our financial position, cash flows or results of operations.

Regulation of Transportation of Crude Oil

Our sales of oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the Interstate Commerce Act of 1887 (“ICA”), the Energy Policy Act of 1992 (“EPAct”), and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport oil and refined products (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. EPAct deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA, which are commonly referred to as “grandfathered rates.” Pursuant to EPAct, FERC also adopted a generally applicable rate-making methodology, which, as currently in effect, allows petroleum pipelines to change their rates provided they do not exceed prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods (“PPI”), plus 1.3%. For the five-year period beginning July 1, 2011, the index will be PPI plus 2.65%.

FERC has also established cost-of-service rate-making, market- based rates and settlement rates as alternatives to the indexing approach. A pipeline may file rates based on its cost of service if there is a substantial divergence between its actual costs of providing service and the rate resulting from application of the index. A pipeline may charge market-based rates if it establishes that it lacks significant market power in the affected markets. Further, a pipeline may establish rates through settlement with all current non-affiliated shippers.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates vary from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors that are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the

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pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could re-enact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in the adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas, transportation rates and terms and conditions of service, which affect the marketing of natural gas that we produce as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others that buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case-by-case basis. To the extent that FERC issues an order that reclassifies transmission facilities as gathering facilities and, depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, non-discriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services vary from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate

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transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental, Health and Safety Regulation

Our exploration, development, production and processing operations are subject to various federal, state and local laws and regulations relating to health and safety, the discharge of materials and environmental protection. These laws and regulations may, among other things: require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and natural gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas, such as wetlands, wilderness areas, or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

These laws and regulations may also restrict the rate of crude oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the crude oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. In addition, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly emissions control, waste handling, disposal, clean-up and remediation requirements for the crude oil and gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretations of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position in the future. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. While we believe that we are in substantial compliance with existing environmental laws and regulations and that current requirements would not have a material

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adverse effect on our financial condition or results of operations, there is no assurance that this will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse effect on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. CERCLA exempts “petroleum, including oil or any fraction thereof” from the definition of “hazardous substance” unless specifically listed or designated under CERCLA. While the EPA interprets CERCLA to exclude oil and fractions of oil, hazardous substances that are added to petroleum or that increase in concentration as a result of contamination of the petroleum during use are not considered part of the petroleum and are regulated under CERCLA as a hazardous substance.

Responsible persons under CERCLA include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. The RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes. The RCRA regulations specifically exclude from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. No such effort has been successful to date.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce crude oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators) and to perform remedial operations to prevent future contamination.

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Pipeline Safety and Maintenance

Pipelines, gathering systems and terminal operations are subject to increasingly strict safety laws and regulations. Both the transportation and storage of refined products and oil involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages and significant business interruption. The U.S. Department of Transportation (“DOT”) has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline and storage facilities. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. In 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law. This Act provides additional requirements related to spill and accident reporting, as well as more stringent oversight of pipelines and increased penalties for violations of safety rules. Since enactment, DOT has initiated a series of rulemakings to implement the new law. DOT has also recently promulgated new regulations extending safety rules to certain low-pressure, small-diameter pipelines in rural areas. Improving pipeline safety, which has the effect of reducing methane leaks, has been proposed as part of the Obama Administration’s methane strategy.

Air Emissions

The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects.

In August 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines (“RICE NESHAP”). The rule may require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on a portion of our engines located at major sources of hazardous air pollutants and all our engines over a certain size regardless of location, following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. On January 14, 2013, the EPA signed final revisions to the 2010 RICE NESHAP to reflect new technical information submitted by stakeholders and in response to lawsuits and administrative petitions. On January 30, 2013 the final RICE NESHAP rule was published in the Federal Register with an effective date of April 1, 2013. Several petitions requesting administrative reconsideration of the 2013 RICE NESHAP were received by the EPA. On August 15, 2014, EPA published its final decision on reconsideration and determined that it would not propose any changes to the regulation based on the petitions.

In June 2010, the EPA formally proposed modifications to existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The EPA finalized the modifications on June 28, 2011 with an effective date of August 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment on a potentially significant percentage of our natural gas compressors.

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The EPA also issued new CAA regulations relevant to hydraulic fracturing in 2012, including a new source performance standard for volatile organic chemicals (“VOCs”) and sulfur dioxide (“SO 2 ”) emissions with expanded applicability to natural gas operations, as well as a new air toxics standard. These rules create significant new technology requirements for controlling wellhead emissions from our operations. The EPA has made several changes to these rules in response to industry and environmental group legal challenges and administrative petitions, including, most recently, a decision to include a specific performance standard for methane in the rules (discussed further below). In general, there is increasing interest in and focus on regulation of methane emissions from oil and natural gas operations, and hydraulic fracturing operations in particular, under the CAA. We cannot predict future regulatory requirements in this area or the cost to comply with such requirements. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce. We further note that states are authorized to regulate methane emissions within their boundaries provided their requirements are not weaker than federal rules.

Climate Change

The United States is a party to the United Nations Framework Convention on Climate Change (“UNFCCC”), an international treaty focused on stabilizing greenhouse gases (“GHGs”) concentrations in the atmosphere at a level that would prevent serious damage to the climate system. The UNFCCC did not establish any substantive obligations for parties to reduce GHGs. The subsequent treaty, the Kyoto Protocol, did establish binding GHG targets for developed countries, but the United States did not ratify it. The Conference of Parties 21 (“COP21”) organised by the United Nations under the Framework Convention on Climate Change and held in Paris during December 2015 resulted in 195 countries, including the United States, committing to work towards limiting global warming and agreeing to a monitoring and review process of GHG emissions. As part of this agreement, the United States, along with other signatories, submitted an Intended Nationally Determined Contribution (“INDC”). The United States’ INDC pledges a 26-28% reduction in its GHGs by 2025 against a 2005 baseline, consistent with the 32% cut by 2030 in the legally binding measures being enforced under the Clean Air Act. Progress towards the INDCs will be reviewed in 2018 and new INDCs are to be submitted in five yearly intervals starting in 2020. The COP 21 agreement is not a treaty and the INDCs are non-binding and submitted voluntary, so that this does not require ratification from the United States. Nevertheless, this will heighten political pressure on the United States to ensure continued compliance with enforcement measures resulting from the Clean Air Act and to bring forward further actions to reduce GHGs in the period post 2030. In the absence of comprehensive climate change legislation, significant regulatory action to regulate GHGs under the federal Clean Air Act has occurred over the past several years. In particular, the Clean Power Plan regulation under the Clean Air Act, which regulates carbon pollution from existing fossil fuel-fired power plants represents a significant portion of the United States’ reductions proposed under the Paris agreement. Any future federal laws, agreements or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

In addition, as stated previously, the EPA has begun to regulate GHG emissions from stationary and mobile sources. The EPA is requiring a reduction in emissions of GHGs from new motor vehicles beginning with the 2012 model year. Furthermore, the EPA published a final rule on June 3, 2010 to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions, such as power plants and oil refineries. This rule was subject to legal challenge that went to the Supreme Court. On June 23, 2014, the Supreme Court issued its decision in Utility Air Regulatory Group v. EPA (No. 12-1146). The Court held that EPA may not require a major source to obtain a PSD or title V permit on the basis of greenhouse gas emissions alone. The Court further held that PSD permits that are otherwise required (based on

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emissions of other pollutants) may continue to require limitations on greenhouse gases emissions based on the application of Best Available Control Technology (“BACT”). The EPA is currently evaluating the implications of the decision and awaiting further action by the U.S. Courts in terms of whether additional rulemaking is necessary.

In addition, the EPA requires the reporting of GHGs from specified large GHG emission sources, including GHGs from petroleum and natural gas systems that emit more than 25,000 tons of GHGs per year. Reporting is required from onshore and offshore petroleum and natural gas production, natural gas processing, transmission and distribution, underground natural gas storage and liquefied natural gas import, export and storage. Pursuant to a settlement agreement, the EPA has also committed to regulate GHGs from new petroleum refineries, though no draft rule has yet been released.

On August 3, 2015, the EPA finalized its NSPS rule regulating greenhouse emissions from new, modified and restructured fossil fuel-fired power plants. In the proposed NSPS, the EPA establishes emission standards for coal plants and for natural gas-fired stationary combustion turbines. The EPA determined that partial carbon capture and sequestration constituted the “best system of emission reduction” (“BSER”) for coal plants. For natural gas plants, the EPA determined that modern, efficient natural gas combined cycle technology constituted the BSER. The NSPS applies to new fossil-fuel fired electric utility generating units over 25 MW and that generate electricity for sale. The NSPS for new sources triggers the need to set standards for existing fossil fuel-fired power plants. On August 3, 2015, the EPA released the final Clean Power Plan, which is regulation designed to reduce carbon pollution from existing fossil fuel-fired power plants. In the Clean Power Plan, the EPA sets forth state-specific emission targets and gives states significant flexibility in determining how they would meet the standards. Limits set by the state to meet the state-specific goals can either apply directly to the power plant or be met through reductions in power plant emissions through implementation of energy efficiency or renewable energy measures in the state. Each state can choose to include measures that EPA determines constitute BSER or may choose additional measures, as long as such measures achieve the emission reduction necessary to meet that state’s goal set by EPA. Throughout the Clean Power Plan, the EPA emphasizes the flexibility of the states to decide how to reduce emissions to meet the state goals, including the use of cap-and-trade programs. While these rules will more negatively impact coal-fired power plants, natural gas-fired power plants may also face liability under the rules and increased costs of operation.

On August 18, 2015, the EPA issued a suite of proposed regulations that would reduce methane emissions from the oil and gas industry, including proposed updates to the NSPS for new and modified sources in the oil and gas industry, a clarification of the source determination rule and a proposed Federal Implementation Plan for new oil and gas sources in Indian Country. The rules were prompted by the Obama Administration’s commitment to reduce methane emissions from the oil and gas sector by 40-45% from 2012 levels by 2025. The NSPS update would require methane and VOC reductions from hydraulically fractured oil wells, which would complement the 2012 NSPS described above. The new proposals would also extend emission reduction requirements “downstream,” covering equipment in the natural gas transmission segment that was not regulated by the 2012 NSPS. The regulations address leaks of methane and propose draft guidelines for the states to reduce VOC emissions from existing oil and gas sources in areas with smog issues. These regulations could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, increased costs of operation and exposure to liability could result.

Several of the EPA’s GHG rules are being challenged in court proceedings and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce.

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While new legislation requiring GHG controls is not expected at the national level in the near term, almost one-half of the states have taken actions to monitor and/or reduce emissions of GHGs, including obligations on utilities to purchase renewable energy and GHG cap and trade programs. Although most of the state level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.

Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas we produce or otherwise cause us to incur significant costs in preparing for or responding to those effects.

Water Discharges

The Federal Water Pollution Control Act, as amended, or the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the United States. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permits issued by the EPA or analogous state agencies. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. Currently, storm water discharges from crude oil and natural gas exploration, production, processing or treatment operations, or transmission facilities are exempt from regulation under the CWA. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as other enforcement mechanisms for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Endangered Species Act

The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

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Employee Health and Safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (the “OSH Act”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSH Act’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used, produced or released in our operations and that this information be provided to employees, state and local government authorities and citizens. In 2012, the Occupational Safety and Health Administration (“OSHA”) issued a hazard alert related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. The alert stated that workers at drill sites can be exposed to excessive levels of respirable silica sand, which can cause lung disease and cancer. Increasing concerns about worker safety at drill sites may lead to increased regulation and enforcement or related tort claims by our employees. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Hydraulic Fracturing

The federal Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment or release of water produced or used during crude oil and natural gas development. Subsurface emplacement of fluids (including disposal wells) is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory authority or the state’s environmental authority. We utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells and operate saltwater disposal wells to dispose of produced water. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the SDWA to expressly exclude hydraulic fracturing without diesel additives from the definition of “underground injection.” However, the U.S. Senate and House of Representatives have considered several bills in recent years to end this exemption, as well as other exemptions for crude oil and gas activities under U.S. environmental laws. The Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”), first introduced in 2011, would amend the SDWA to repeal the exemption from regulation under the UIC program for hydraulic fracturing. This bill has been reintroduced in each congressional session since it was initially proposed but has not yet garnered enough support to be put to a vote. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, to adhere to certain construction specifications, to fulfill monitoring, reporting and recordkeeping obligations, and to meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process. Note that each of the above components of the FRAC Act have become increasingly common in state laws since the FRAC Act was first introduced. Other recent bills in the U.S. House of Representatives would end certain exemptions for oil and natural gas operations related to permitting requirements for multiple commonly owned and adjacent sources of hazardous air pollutants under the CAA and permitting requirements for stormwater discharges under the CWA. If the exemptions for hydraulic fracturing are removed from U.S. environmental laws, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.

Federal agencies have also begun to directly regulate hydraulic fracturing. The EPA has recently asserted federal regulatory authority over, and issued permitting guidance for, hydraulic fracturing involving diesel additives under the SDWA’s UIC Program. As a result, service providers or companies that use diesel products in the hydraulic fracturing process are expected to be subject to additional permitting requirements or enforcement actions under the SDWA. The EPA has also issued new CAA regulations relevant to hydraulic fracturing in 2012, including the NSPS for VOC and SO 2 emissions with expanded applicability to natural gas operations and new national emission standards

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for hazardous air pollutants standards for air toxics, which are discussed in more detail above. These regulatory developments are indicative of increasing federal regulatory activity related to hydraulic fracturing, which has the potential to create additional permitting, technology, recordkeeping and site study requirements, among others, for our business. The EPA is also collecting information as part of a multi-year study into the effects of hydraulic fracturing on drinking water. The results of this study could result in additional regulations, which could lead to operational burdens similar to those described above. The U.S. Department of the Interior has likewise developed comprehensive regulations for hydraulic fracturing on federal land, which remain under review by the White House’s Office of Management and Budget.

Several state governments in the areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosure of the chemicals used in fracturing. For example, several states, such as Colorado, have implemented rules requiring hydraulic fracturing operators to sample ground- and surface waters near proposed well sites before operations can begin, and to sample the same sites again after fracturing operations are complete. A majority of states around the country, including Colorado and Texas, have also adopted some form of fracturing fluid disclosure law to compel disclosure of fracturing fluid ingredients and additives that are not subject to trade secret protection. Other states, such as Ohio and Texas, have begun to study potential seismic risks related to underground injection of fracturing fluids. Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.

At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.

Other Laws

The Oil Pollution Act of 1990, as amended (“OPA”), establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the United States. The OPA assigns liability to each responsible party for oil clean-up costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the clean-up, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental clean-up and restoration costs that could be incurred in connection with an oil spill.

The National Environmental Policy Act of 1969, as amended (“NEPA”), requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment before their commencement. Generally, federal agencies must prepare either an environmental assessment or an environmental impact statement, depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the environment. The NEPA process involves significant public input through comments on alternatives to the proposed project or resource-specific mitigation options for the project. NEPA decisions can be and often are appealed through the administrative and federal court systems by process participants. Environmental groups in the United States have increasingly focused on the required public consultation process under NEPA as a forum for voicing concerns over continued development of fossil fuel energy sources in the

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United States and for seeking expansive environmental reviews of projects that relate to the production, transportation, or combustion of these fuels, including evaluating the impacts of projects on climate change. Although we believe that our actions do not typically trigger NEPA analysis, should we ever be subject to NEPA, the process could result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and result in certain instances in litigation and/or the cancellation of certain leases.

Industry Segment and Geographic Information

We operate in one industry segment, which is the exploration, development and production of oil, NGLs and natural gas. Our current operational activities and consolidated revenues are generated from markets exclusively in the U.S., and we have no long lived assets located outside the U.S.

Employees

As of December 31, 2015, we had 53 employees, including seven engineers and geoscientists, five land professionals and eighteen field operating personnel. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed.

Facilities

We lease approximately 16,000 square feet of office space at Suite 200, 600 Bailey Avenue, Fort Worth, Texas, where our principal offices are located. We maintain field offices in Atascosa County, Texas and Albany, Texas.

Item 1A. Risk Factors.

An investment in our common stock involves significant risks. You should carefully consider the risks described below and the other information in this document before you decide to invest in our common stock. If any of the following risks actually occurs, our business, prospects, financial condition and results of operations could be materially affected, the trading price of our common stock could decline and you could lose all or part of your investment.

Risks Related to the Oil and Natural Gas Industry and Our Business

Oil, natural gas and NGL prices are volatile. A substantial or extended decline in the price of these commodities may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Our revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices we receive for our oil, natural gas and NGLs. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and this volatility may continue 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:

· general worldwide and regional economic and political conditions;

· the domestic and global supply of, and demand for, oil, natural gas and NGLs;

· the cost of exploring for, developing, producing and marketing oil, natural gas and NGLs;

· the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines and other transportation facilities;

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· the price and quantity of imports of foreign oil, natural gas and NGLs;

· the level of global oil, natural gas and NGL exploration and production;

· the level of global oil, natural gas and NGL inventories;

· weather conditions and natural disasters;

· domestic and foreign governmental laws, regulations and taxes;

· volatile trading patterns in commodities futures markets;

· price and availability of competitors’ supplies of oil, natural gas and NGLs;

· the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and the ability of OPEC and other producing nations to agree to and maintain production levels;

· technological advances affecting energy consumption; and

· the price and availability of alternative fuels.

Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 60% of our estimated proved reserves as of December 31, 2015 was attributed to oil, our financial results are more sensitive to movements in oil prices.

As of December 31, 2015, we had commodity price hedging agreements on approximately 54% of our expected production for 2016 or 2,276 Bo/d. Since December 31, 2015, we have entered into additional WTI crude oil swaps covering a total of 174,550 barrels for the period of May 2016 through December 2016. The addition of these swaps increased the company’s crude oil swap coverage to a total of approximately 2,847 barrels of oil per day, or approximately 70% of our expected oil production for 2016 at an average swap price of $68.69 per barrel. To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil and natural gas that could materially and adversely affect our business and results of operations.

The decline in the SEC mandated oil price for use in PV-10 calculations from $94.99 per barrel to $50.28 per barrel has had a material reduction in the PV-10 valuation of our proved reserves and may continue if oil and natural gas prices remain lower. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies.

WTI oil prices have declined from over $100 per barrel in September 2014 to $45.98 per barrel at April 30, 2016. Such a decline in oil price, if sustained, will have a material impact on our annual revenues and has caused us to take actions to reduce the costs of drilling and our operations. For example, we have moderated our 2016 drilling plan by reducing the number of wells planned from 16 wells in 2015 to 10 wells planned for 2016, with an expected capital budget of between $35 million and $45 million, in order to ensure our drilling budget is broadly matched by our operating cash flows and the availability of capital under our financing arrangements.

Prolonged further sustained declines in oil, natural gas or NGL prices may act to reduce our cash flows further and adversely affect our financial condition. Our liquidity would be reduced, our access to equity or long-term debt might be restricted, and our ability to meet our capital expenditure obligations and financial commitments might be adversely affected. We may choose to defer drilling activity and/or production from existing wells for a number of reasons, including the following:

· drilling activity is sanctioned on the expectation of matching the drilling budget with operating cash flows and securing reasonable rates of returns based on the then prevailing oil, natural gas and NGL prices; if those prices decline and operating cash flows are reduced, there is a risk that drilling may be curtailed or postponed; and

· operating costs on our Eagle Ford properties are so low that production from these properties would likely continue to contribute to cash flows, but we may choose to defer production in the event that we consider there may be greater value in producing later.

Furthermore, prolonged sustained further declines in oil, natural gas or NGL prices may reduce the amount of our estimated oil, natural gas and NGL reserves, the carrying value of our oil, natural

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gas and NGL reserves, the PV-10 valuations of our oil, natural gas and NGL reserves, and the standardized measure relating to oil, natural gas and NGL reserves.

Our future revenues are dependent on our ability to successfully replace our proved producing reserves.

Our business strategy is to generate profit through the acquisition, exploration, development and production of crude oil and natural gas reserves. Future success therefore depends on our ability to find, develop or acquire additional crude oil and natural gas reserves that are economically recoverable. Further to this, our proved reserves generally decline when produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves or both. We may not be able to find, develop or acquire additional reserves on an economically viable basis. Furthermore, if crude oil and natural gas prices increase, the cost of finding, developing or acquiring additional reserves could also increase.

Exploration and development activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and operating wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

· lack of prospective acreage available on acceptable terms;

· unexpected or adverse drilling conditions;

· elevated pressure or irregularities in geologic formations;

· equipment failures or accidents;

· adverse weather conditions;

· title problems;

· limited availability of financing upon acceptable terms;

· reductions in oil, NGLs and natural gas prices;

· compliance with governmental requirements; and

· shortages or delays in the availability of drilling rigs, equipment and personnel.

Even if our drilling efforts are successful, our wells, once completed, may not produce reserves of crude oil, NGLs or natural gas that are economically viable or that meet our prior estimates of economically recoverable reserves. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial position by reducing our available cash and liquidity. In addition, the potential for production decline rates for our wells could be greater than we expect. Because of the risks and uncertainties inherent to our businesses, our future drilling results may not be comparable to our historical results.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves with resulting adverse effects on our cash flow and liquidity.

The oil and natural gas industry is capital intensive. We currently make, and expect to continue to make, substantial capital expenditures for the acquisition, development and exploration of oil, natural gas and NGL reserves. We currently expect to allocate between $35 million and $45 million under our 2016 capital program to the drill and complete 10 wells across our properties in the Eagle Ford Shale. We expect to fund our 2016 capital expenditures with cash generated by operations, our undrawn capacity under our revolving credit facility and funding available under our Joint Development Agreement with IOG.

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The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, crude oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital are subject to a number of variables, including:

· our proved reserves;

· the amount of crude oil, natural gas and NGLs we are able to produce from existing wells;

· the prices at which our crude oil, natural gas and NGLs are sold;

· the costs at which our crude oil, natural gas and NGLs are extracted;

· global credit and securities markets;

· the ability and willingness of lenders and investors to provide capital and the cost of the capital; and

· our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower crude oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, or we are unable to secure funding under our Joint Development Agreement with IOG, we may have limited ability to obtain the capital necessary to sustain our operations and growth 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 cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition and results of operations.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and natural gas business involves operating hazards such as:

· well blowouts;

· mechanical failures;

· explosions;

· pipe or cement failures and casing collapses, which could release natural gas, oil, drilling fluids or hydraulic fracturing fluids;

· uncontrollable flows of oil, natural gas or well fluids;

· fires;

· geologic formations with abnormal pressures;

· handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;

· pipeline ruptures or spills;

· releases of toxic gases; and

· other environmental hazards and risks.

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Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others.

We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that our management believes to be prudent. However, insurance against all operational risks is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented.

In addition, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure investors that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Our planned exploratory drilling involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques, which are subject to risks. As a result, drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to:

· landing our well bore in the desired formation;

· staying in the desired formation while drilling horizontally through the formation;

· running our casing the entire length of the well bore; and

· being able to run tools and other equipment consistently through the well bore.

Risks that we face while completing our wells include, but are not limited to:

· being able to fracture stimulate the planned number of stages;

· being able to run tools the entire length of the well bore during completion operations; and

· successfully cleaning out the well bore after completion of the final fracture stimulation stage.

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise and/or crude oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

SEC rules could limit our ability to book additional PUDs in the future .

SEC rules require that, subject to limited exceptions, our PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement

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limits our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill those wells within the required five-year time frame.

Our identified drilling locations are scheduled to be developed over several 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 substantial amount of capital that would be necessary to drill such locations.

Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

· the ongoing review and analysis of geologic and engineering data;

· the availability of sufficient capital resources to us and the other participants for drilling and completing of the prospects;

· the approval of the prospects by other participants once additional data has been compiled;

· economic and industry conditions at the time of drilling, including prevailing and anticipated prices for crude oil and natural gas and the availability and prices of drilling rigs and personnel;

· the ability to maintain, extend or renew leases and permits on reasonable terms for the prospects; and

· the opportunity to divert our drilling budget to preferred prospects on acquired acreage or to secure other acreage by farming in.

Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells that are currently part of our capital plan may be based on results of drilling activities in other areas that we believe are geologically similar to a prospect rather than on analysis of seismic or other data in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from results in other areas. In addition, our drilling schedule may vary from our expectations because of future uncertainties. In addition, our ability to produce oil and natural gas may be significantly affected by the availability and prices of hydraulic fracturing equipment and personnel.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well 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 potential 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. Therefore, our actual drilling activities may materially differ from those presently identified.

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.

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A large proportion of our total estimated proved reserves at December 31, 2015 was undeveloped. 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, 2015, approximately 67% of our total estimated reserves were classified as proved undeveloped. Recovery of undeveloped reserves requires successful drilling and incurrence of significant capital expenditures. Our approximately 26.9 MMBoe of estimated proved undeveloped reserves will require an estimated $285 million of development capital over the next five 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.

Further, our reserves data assume that we can and will make these expenditures and that these operations will be conducted successfully. These assumptions, however, may not prove correct. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write them off. Any such write-offs of our reserves could reduce our ability to borrow and adversely affect our liquidity.

Our producing properties are located primarily in the Eagle Ford Shale of South Texas, making us vulnerable to risks associated with operating in one geographic area.

Approximately 90% of our production during the year ended December 31, 2015 was derived from our properties in the Eagle Ford Shale region of South Texas. As a result of this geographic concentration, we may be disproportionately exposed to the effect 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, weather events or interruption of the processing or transportation of crude oil or natural gas. Additionally, we may be exposed to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in many or all of our wells within the Eagle Ford Shale.

Approximately 72% of our net Eagle Ford Shale leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our crude oil, natural gas and NGLs reserves and future production and, therefore, our future cash flow and income.

Approximately 72% of our net Eagle Ford Shale leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, natural gas and NGLs regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future crude oil, natural gas and NGLs reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.

There are uncertainties inherent in estimating crude oil and natural gas reserves and their estimated value, including many factors beyond our control. The reserve data in this registration statement represent only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. Reservoir

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engineering also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Accordingly, actual production, crude oil and natural gas prices, revenue, taxes, operating expenses, expenditures and quantities of recoverable crude oil and natural gas reserves will likely vary, possibly materially, from estimates. Any significant variance in our estimates or the accuracy of our assumptions could materially affect the estimated quantities and present value of reserves shown in this registration statement.

Certain of our oil producing properties are located on the Fort Peck Reservation, making us vulnerable to risks associated with tribal sovereignty laws and regulations pertaining to the operation of oil and gas properties on Native American tribal lands.

Certain of our oil and natural gas properties are located on the Fort Peck Reservation in Montana, or the “Reservation.” Operation of oil and natural gas interests on Native American tribal lands presents unique considerations and complexities that arise from the fact that Native American tribes are “dependent” sovereign nations located within states but are subject only to tribal laws and treaties with, and the laws and Constitution of, the United States. This creates an overlay of three jurisdictional regimes — Native American, federal and state. These considerations and complexities could arise around various aspects of our operations, including real property considerations, permitting, employment practices, environmental matters and taxes.

Furthermore, because tribal property is considered to be held in trust by the federal government, before we can take actions such as drilling, pipeline installation or similar actions, we are required to obtain approvals from various federal agencies, including the Bureau of Indian Affairs and the Bureau of Land Management. We are also required to obtain approvals from the Tribe for surface use access on certain of our properties. Gaining these approvals could result in delays in implementation of, or otherwise prevent us from implementing, our development program.

We have limited control over activities in properties we do not operate, which could reduce our production and revenues and could increase our costs.

We utilize joint operating agreements on certain of our conventional oil, natural gas and NGL properties where we have less than 100% working interest. These non-operated activities in aggregate accounted for approximately 3% of our group production in 2015. Other companies may be operators under these joint operating agreements and, as a non-operating working interest owner, we will be dependent to a degree on the efficient and effective management of the operators. The objectives and strategy of those operators may not always be consistent with our objectives and strategy. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. 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 in our best interests could reduce our production and revenues from our conventional assets or could create liability for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards.

Such events could significantly and adversely affect our anticipated exploration and development activities of our non-operated properties. Under our joint operating agreements, we will be required to pay our percentage interest share of all costs and liabilities incurred by the operator on behalf of the working interest owners in connection with joint venture activities. In common with other working interest owners, if we fail to pay our share of any costs and liabilities, we may be deemed to have elected non-participation with respect to operations affected and may be subject to loss of interest through foreclosure of operator liens invoked by participating working interest owners and subject us to non-consent penalties.

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We depend upon several significant customers for the sale of most of our crude oil, natural gas and NGLs production.

For the year ended December 31, 2015, purchases by our largest four customers accounted for 38%, 20%, 16% and 11%, respectively, of our total sales revenues. While we believe that we can procure substitute or additional customers to offset the loss of one or more of our current customers, there is no assurance that we would be successful in doing so on terms acceptable to us or at all. The loss of one or more of such customers could limit our access to suitable markets for the crude oil, natural gas and NGLs we produce. The availability of a ready market for any crude oil, natural gas and/or NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of crude oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of crude oil and natural gas production and federal regulation of crude oil, natural gas and NGLs sold in interstate commerce. We cannot assure you that we will continue to have ready access to suitable markets for our future crude oil, natural gas and NGL production.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

The discounted future net cash flows in this registration statement are not necessarily the same as the current market value of our estimated crude oil and natural gas reserves. As required by the current requirements for crude oil and natural gas reserve estimation and disclosures, the estimated discounted future net cash flows from proved reserves are based on the average of the sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by various factors, including:

· the actual prices we receive for crude oil and natural gas;

· our actual operating costs in producing crude oil and natural gas;

· the amount and timing of actual production;

· supply and demand for crude oil and natural gas;

· increases or decreases in consumption of crude oil and natural gas; and

· changes in governmental regulations or taxation.

In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements 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 gas industry in general.

Our derivative activities could result in financial losses or could reduce our income.

Because crude oil and natural gas prices are subject to volatility, we may periodically enter into price-risk-management transactions such as fixed-rate swaps, costless collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and natural gas production and thereby achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of crude oil and natural gas. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in crude oil and natural gas prices.

These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of crude oil and natural gas or a sudden, unexpected event materially impacts crude oil or natural gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

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If crude oil and natural gas prices decrease, we may be required to write-down the carrying values of our crude oil and natural gas properties.

We review our proved crude oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. 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 write down the carrying value of our crude oil and natural gas properties, which may result in a decrease in the amount we can borrow under our credit facilities. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our credit facilities and adversely impact our results of operations for the periods in which such charges are taken.

Our inability to market our crude oil and natural gas could adversely affect our business.

Market conditions or the unavailability of satisfactory crude oil and natural gas transportation arrangements may hinder our access to crude oil and natural gas markets or delay production. The availability of a ready market for our crude oil and natural gas production depends on a number of factors, including the demand for and supply of crude oil and natural gas and the proximity of reserves to pipelines and gathering 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 favorable terms could adversely impact our business and results of operations.

Our productive properties may be located in areas with limited or no access to pipelines, thereby requiring compression facilities or delivery by other means, such as trucking and train. Such restrictions on our ability to sell our crude oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended period of time, possibly causing us to lose a lease due to the lack of commercially established production.

We generally deliver our crude oil and natural gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our crude oil and natural gas production may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system or for other reasons as dictated by the particular agreements. We may also enter into firm transportation arrangements for additional production in the future. Because we are obligated to pay fees on minimum volumes to our service providers under these agreements regardless of actual volume throughput, these firm transportation agreements may be significantly more costly than interruptible or short-term transportation agreements, which could adversely affect our business and results of operations.

A portion of our crude oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, or field personnel issues or strikes. We may also voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted or curtailed, it could adversely affect our business and results of operations.

The terms of our revolving credit facility and the indenture that governs our 8.75% Senior Notes due 2019 may restrict our operations, particularly our ability to respond to changes or to take certain actions.

The indenture that governs our 8.750% Senior Notes due 2019 and our revolving credit facility contain a number of restrictive covenants that impose significant operating and financial restrictions

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on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to:

· incur additional indebtedness and guarantee indebtedness;

· pay dividends or make other distributions or repurchase or redeem capital stock;

· prepay, redeem or repurchase certain debt;

· issue certain preferred stock or similar equity securities;

· make loans and investments;

· sell assets;

· incur liens;

· enter into transactions with affiliates;

· alter the businesses we conduct;

· enter into agreements restricting our subsidiaries’ ability to pay dividends; and

· consolidate, amalgamate, merge or sell all or substantially all of our assets.

In addition, the restrictive covenants in our revolving credit facility require us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we may be unable to meet them.

A breach of the covenants or restrictions under the indenture that governs the notes or under our revolving credit facility could result in an event of default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related debt and may result in the acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In the event our lenders or holders of the notes accelerate the repayment of our borrowings, we and our subsidiaries may not have sufficient assets to repay that indebtedness.

As a result of these restrictions, we may be:

· limited in how we conduct our business;

· unable to raise additional debt or equity financing to operate during general economic or business downturns; or

· unable to compete effectively or to take advantage of new business opportunities.

These restrictions may affect our ability to grow in accordance with our strategy. In addition, our financial results, our substantial indebtedness and our credit ratings could adversely affect the availability and terms of our financing.

Our level of indebtedness may increase, reducing our financial flexibility.

We intend to fund our capital expenditures in 2016 through cash flow from operations, from borrowings under our credit facilities, funding available under our Joint Development Agreement with IOG and, if necessary, through debt or equity financings. Our ability to make the necessary capital investment to maintain or expand our asset base and develop oil and natural gas reserves will be impaired if cash flow from operations is reduced and external sources of capital become limited or unavailable. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. Our level of debt could adversely affect our business and results of operations in several important ways, including the following:

· a portion of our cash flow from operations would be used to pay interest on borrowings;

· the covenants contained in our credit facilities limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect

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our flexibility in planning for, and reacting to, changes in general business and economic conditions;

· a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;

· a leveraged financial position would make us more vulnerable to economic downturns and decreases in commodity prices and could limit our ability to withstand competitive pressures; and

· a debt that we incur under our credit facilities will be at variable rates, which could make us vulnerable to an increase in interest rates.

Increased costs of capital could adversely affect our business.

Our business and operating results can be adversely affected by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, which would impact our ability to finance our operations. We will require continued access to capital for the foreseeable future. A significant reduction in the availability of credit could materially and adversely affect our business, results of operations and financial condition.

Competition in the crude oil and natural gas industry is intense and many of our competitors have resources that are greater than ours.

The oil and natural gas industry is highly competitive. Public integrated and independent oil and gas companies, private equity backed and private operators are all active bidders for desirable crude oil and natural gas properties as well as the equipment and personnel required to operate those properties. Many of these companies have substantially greater financial resources, staff and facilities than we do. There is a risk that increased industry competition will adversely impact our ability to purchase assets or secure services at prices that will allow us to generate sufficient returns on investment in the future.

The loss of any of our key personnel could adversely affect our business, financial condition, the results of operations and future growth.

We are reliant on a number of key members of our executive management team, and we do not have employment agreements with any of them. Loss of such personnel may have an adverse effect on our performance. Certain areas in which we operate are highly competitive regions and competition for qualified personnel is intense. We may be unable to hire suitable field personnel for our technical team or there may be periods of time where a particular position remains vacant while a suitable replacement is identified and appointed. Our ability to manage our growth will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. We may not be successful in attracting and retaining the personnel required to grow and operate our business profitably.

Our ability to manage growth will have an impact on our business, financial condition and results of operations.

Our growth historically has been achieved through the acquisition of leaseholds and the expansion of our drilling programs. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, potentially adversely affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:

· our ability to obtain leases or options on properties;

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· our ability to identify and acquire new exploratory prospects;

· our ability to develop existing prospects;

· our ability to continue to retain and attract skilled personnel;

· our ability to maintain or enter into new relationships with project partners and independent contractors;

· the results of our drilling programs;

· commodity prices; and

· our access to capital.

We may not be successful in upgrading our technical, operational and administrative resources or increasing our internal resources sufficiently to provide certain of the services currently provided by third parties, and we may not be able to maintain or enter into new relationships with project partners and independent contractors on financially attractive terms, if at all. Our inability to achieve or manage growth may materially and adversely affect our business, results of operations and financial condition.

We may incur losses as a result of title deficiencies.

We may lose title to, or interests in, our leases and other properties if the conditions to which those interests are subject are not satisfied or if insufficient funds are available to meet the commitments.

The existence of title differences with respect to our crude oil and natural gas properties could reduce their value or render such properties worthless, which would have a material adverse effect on our business and financial results. We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of our crude oil and natural gas properties. As is customary in the industry in which we operate, we generally rely upon the judgment of crude oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract, and we generally make title investigations and receive title opinions of local counsel before we commence drilling operations. In some cases, we perform curative work to correct deficiencies in the marketability or adequacy of the title assigned to us. In cases involving more serious title problems, the amount paid for affected crude oil and natural gas leases can be lost, and the target area can become undrillable. While we undertake to cure all title deficiencies prior to drilling, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease, our investment in the well and the right to produce all or a portion of the minerals under the property. A significant portion of our acreage is undeveloped leasehold, which has a greater risk of title defects than developed acreage.

Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.

The conduct of exploration for, and production of, hydrocarbons may expose our staff to potentially dangerous working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. If any of our employees suffer injury or death, compensation payments or fines may have to be paid, and such circumstances could result in the loss of a license or permit required to carry on the business, or other legislative sanction, all of which have the potential to materially and adversely affect our business, results of operations and financial condition.

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes and historical industry operations and waste disposal practices. Under certain

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environmental laws and regulations, we may be liable, regardless of whether we were at fault, for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition and results of operations. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, as well as collect penalties for violations or obtain damages for any related personal injury or property damage. Some sites we operate are 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. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling, emission, waste management or clean-up requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise materially and adversely affect our business, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance.

In addition, our operations and financial performance may be adversely affected by governmental action, including delay, inaction, policy change or the introduction of new, or amendment of or changes in interpretation of existing legislation or regulations, particularly in relation to access to infrastructure, environmental regulation (including in respect of carbon emissions and management), royalties and production and exploration licensing. Federal and state regulators are increasingly targeting greenhouse gas emissions from oil and gas operations. While these regulatory efforts are evolving, they may require the installation of emission controls or mandate other action that may result in increased costs of operation, delay, uncertainty or exposure to liability.

Hydraulic fracturing, which is the process used for releasing hydrocarbons from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is an important and commonly used process in the completion of unconventional crude oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate crude oil or natural gas production. Currently, hydraulic fracturing is primarily regulated in the United States at the state level, which generally focuses on regulation of well design, pressure testing and other operating practices. However, some states and local jurisdictions across the United States, including states in which we operate, have begun adopting more restrictive regulation, including measures such as:

· required disclosure of chemicals used during the hydraulic fracturing process;

· restrictions on wastewater disposal activities;

· required baseline and post-drilling sampling of water supplies in close proximity to hydraulic fracturing operations;

· new municipal or state land use regulations, such as changes in setback requirements, which may restrict drilling locations or related activities;

· financial assurance requirements, such as the posting of bonds, to secure site restoration obligations; and

· local moratoria or even bans on crude oil and natural gas development utilizing hydraulic fracturing in some communities.

At the U.S. federal level, hydraulic fracturing that does not involve the use of diesel fuels is exempt from regulation under the Safe Drinking Water Act (“SDWA”). However, the United States Congress (“Congress”) has considered and likely will continue to consider eliminating this regulatory exemption, which could subject hydraulic fracturing activities to regulation and permitting by the

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Environmental Protection Agency (“EPA”) under the SDWA. Congressional action will be informed by a study commenced in 2011 by the EPA on the impacts of hydraulic fracturing on drinking water resources, with final results anticipated in 2016. Despite the existing exemption, the EPA has begun utilizing other legal authorities in various ways to regulate portions of the hydraulic fracturing process, exemplified by its issuance of regulations under the Clean Air Act limiting emission of pollutants during the hydraulic fracturing process, as well as its recent initiation of a proposed rulemaking under the Toxic Substances Control Act to obtain data on chemical substances and mixtures used in hydraulic fracturing. In addition, the United States Department of the Interior has proposed comprehensive regulations governing the use of hydraulic fracturing on federally managed lands.

These efforts by Congress, federal regulators, states and local governments could result in additional costs, delay and operational uncertainty that could limit, preclude or add costs to use of hydraulic fracturing in our drilling operations.

Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGLs services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Drilling activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs, including the Eagle Ford, requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. The effects of climate change may further exacerbate water scarcity in certain regions.

Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of crude oil and natural gas. In particular, regulatory focus on disposal of produced water and drilling waste through underground injection has increased because of alleged links between such injection and regional seismic impacts in disposal areas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could materially and adversely affect our business, results of operations and financial condition.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

The EPA finalized its New Source Performance Standard (“NSPS”) rule regulating carbon dioxide from new, modified and reconstructed fossil fuel-fired power plants and the Clean Power Plan

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for existing fossil fuel-fired power plants. While these rules will more negatively impact coal-fired power plants, natural gas-fired power plants may also face liability under the rules and increased costs of operation.

In August 2015, the EPA released proposed regulation intended to reduce methane emissions from the oil and gas industry, including throughout the natural gas supply chain. The methane regulations, once finalized could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, increased costs of operation and exposure to liability could result.

In addition, Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane that are understood to contribute to global warming. While comprehensive climate legislation will likely not be passed by either house of Congress in the near future, energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions such as electric power plants, smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

Acts of terrorism (including eco-terrorism and cyber attacks) 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 and cyber-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.

Certain federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of future legislation.

We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. Certain legislation introduced in the Congress, if enacted into law, would make significant changes to U.S. tax laws, including, but not limited to, the elimination of certain key federal income tax incentives currently available to crude oil and natural gas exploration and production companies.

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These or any other similar changes in federal tax laws could defer or eliminate certain tax deductions that are currently available with respect to crude oil and natural gas exploration and development, and any such change could materially and adversely affect our business, results of operations and financial condition.

General economic conditions could adversely affect our business and future growth.

Instability in the global financial markets may have a material impact on our liquidity and financial condition, and we may ultimately face major challenges if conditions in the financial markets were to materially change or worsen. Our ability to access the capital markets or to borrow money may be restricted or may be more expensive at a time when we would need to raise capital, which could have an adverse effect on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Such economic conditions could have an impact on our customers, causing them to fail to meet their obligations to us. In addition, it could have an impact on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments.

Also, market conditions could have an impact on our crude oil and natural gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection, which could lead to reductions in the demand for crude oil and natural gas, or reductions in the prices of oil and natural gas or both, which could have an adverse impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of changing economic conditions cannot be predicted, they may materially and adversely affect our business, results of operations and financial condition.

Changes in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price our actual crude oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we will use to price our crude oil and natural gas sales sometimes will reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict crude oil and natural gas differentials. Changes in differentials between the benchmark price for crude oil and natural gas and the reference or regional index price we reference in our sales contracts could materially and adversely affect our business, results of operations and financial condition.

Recent federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our crude oil and natural gas production. Under the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), the Commodity Futures Trading Commission (“CFTC”) issued regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are exempt from these limits. The position limits regulation was vacated by the United States District Court for the District of Columbia in September 2012. The CFTC has appealed the District Court’s decision and its Chairman has stated that the agency is working on developing a new proposed rulemaking to address position limits. The CFTC has finalized other regulations, including critical rulemakings on the “swap” and “swap dealer” definitions, swap dealer registration, swap data reporting and mandatory clearing, among others. The Dodd-Frank Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. The legislation may also require the counterparties to our derivative contracts to spin off some of their

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derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislation and any new regulations could:

· significantly increase the cost of some derivative contracts (including through requirements to post collateral that could adversely affect our available liquidity);

· materially alter the terms of some derivative contracts;

· reduce the availability of some derivatives to protect against risks we encounter;

· reduce our ability to monetize or restructure our existing derivative contracts; and

· potentially increase our exposure to less creditworthy counterparties.

If we reduce our use of derivatives as a result of the new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our financial condition and results of operations.

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

In accordance with our business strategies, we periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

· recoverable reserves;

· future crude oil and natural gas prices and their appropriate differentials;

· development and operating costs; and

· 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 potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems 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.

Significant acquisitions and other strategic transactions may involve other risks, including:

· diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

· the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

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· difficulty associated with coordinating geographically separate organizations; and

· the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect, including with respect to estimated proved reserves, production volume or cost savings from operating synergies, within our expected time frame. Anticipated benefits of an acquisition may also be offset by operating losses relating to changes in commodity prices in crude oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. Failure to realize the benefits we anticipate from an acquisition may materially and adversely affect our business, results of operations and financial condition.

Risks Related to our Common Stock

An active trading market for our common stock may not develop on Nasdaq and the trading price for our common stock may fluctuate significantly.

While we have applied for the listing of our common stock on Nasdaq, a liquid public market may not develop or be sustained. If an active public market on Nasdaq for our common stock does not develop, the market price and liquidity of our shares may be materially adversely affected. In the past, following periods of volatility in the market price of a company’s securities, shareholders often instituted securities class action litigation against that company. If we were involved in a class action suit, it could divert the attention of senior management and, if adversely determined, could have a material adverse effect on our results of operations and financial condition.

The market price and trading volume of our common stock may be volatile and may be affected by economic conditions beyond our control.

The market price of our common stock may be highly volatile and could be subject to wide fluctuations. The market prices of securities of oil and gas exploration and production companies have often experienced fluctuations that have been unrelated or disproportionate to the operating results of these companies. In addition, the trading volume of our common stock may fluctuate and cause significant price variations to occur. If the market price of our common stock declines significantly, you may be unable to resell your shares at or above the purchase price, if at all. We cannot assure you that the market price of our shares will not fluctuate or significantly decline in the future.

Some specific factors that could negatively affect the price of our common stock or result in fluctuations in their price and trading volume include:

· actual or expected fluctuations in our operating results;

· actual or expected changes in our growth rates or our competitors’ growth rates;

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· changes in commodity prices for hydrocarbons we produce;

· changes in market valuations of similar companies;

· changes in our key personnel;

· potential acquisitions and divestitures;

· changes in financial estimates or recommendations by securities analysts;

· changes or proposed changes in laws and regulations affecting the oil and natural gas industry;

· changes in trading volume of our common stock on Nasdaq;

· sales of our common stock by us, our executive officers or our shareholders in the future;

· conditions in the crude oil and natural gas industry in general; and

· conditions in the financial markets or changes in general economic conditions.

We are an emerging growth company and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies may make the common stock less attractive to investors and, as a result, adversely affect the price of the common stock and result in a less active trading market for the common stock.

We are an emerging growth company as defined in the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. For example, we have elected to rely on an exemption from the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act relating to internal control over financial reporting, and we will not provide such an attestation from our auditors. We may also take advantage of an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and exemptions from the requirements of holding advisory “say-on-pay” votes on executive compensation and shareholder advisory votes on golden parachute compensation not previously approved.

We may avail ourselves of these disclosure exemptions until we are no longer an emerging growth company. We cannot predict whether investors will find the common stock less attractive because of our reliance on some or all of these exemptions. If investors find the common stock less attractive, it may adversely impact the price of the common stock and there may be a less active trading market for the common stock.

We will cease to be able to take advantage of the disclosure exemptions as an emerging growth company upon the earliest of:

· the end of the fiscal year in which the fifth anniversary of completion of an initial public offering occurs;

· the end of the first fiscal year in which the market value of our common stock held by non-affiliates exceeds $700 million as of the end of the second quarter of such fiscal year;

· the end of the fiscal year in which we have total annual gross revenues of at least $1 billion; and

· the date on which we have issued more than $1 billion in non-convertible debt securities in any rolling three-year period.

If we fail to establish and maintain proper internal controls, our ability to produce accurate financial statements or comply with applicable regulations could be impaired.

Section 404(a) of the Sarbanes-Oxley Act requires that, beginning with our annual report for the year ending December 31, 2017, our management assess and report annually on the effectiveness of our internal controls over financial reporting and identify any material weaknesses in our internal controls over financial reporting. Once we are no longer a smaller reporting company, Section 404(b) of the Sarbanes-Oxley Act will require our independent registered public accounting firm to issue an

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annual report that addresses the effectiveness of our internal controls over financial reporting. We expect, however, to rely on the exemptions provided in the JOBS Act, and consequently will not be required to comply with SEC rules that implement Section 404(b) of the Sarbanes-Oxley Act until such time as we are no longer an emerging growth company.

Our first Section 404(a) assessment will take place beginning with our annual report for the year ending December 31, 2017. In connection with the review of our unaudited condensed consolidated financial statements for the nine months ended September 30, 2015, management has identified a material weakness in the financial close process relating to the failure to record certain balance sheet entries and balance sheet reclassification adjustments during the interim quarter end closing process. Though management expects to remediate this deficiency going forward, the presence of further material weaknesses could result in financial statement errors which, in turn, could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results or our auditors may be required to issue a qualified audit report. We might not identify one or more material weaknesses in our internal controls in connection with evaluating our compliance with Section 404(a) of the Sarbanes-Oxley Act. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal controls over financial reporting, we will need to expend significant resources and provide significant management oversight. Implementing any appropriate changes to our internal controls may require specific compliance training of our directors and employees, entail substantial costs in order to modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.

If either we are unable to conclude that we have effective internal controls over financial reporting or, at the appropriate time, our independent auditors are unwilling or unable to provide us with an unqualified report on the effectiveness of our internal controls over financial reporting as required by Section 404(b) of the Sarbanes-Oxley Act, investors may lose confidence in our operating results, the price of our common stock could decline and we may be subject to litigation or regulatory enforcement actions. In addition, if we are unable to meet the requirements of Section 404 of the Sarbanes-Oxley Act, we may not be able to remain listed on Nasdaq.

We will continue to be controlled by our existing owners, whose interests may differ from those of our public stockholders.

As of April 30, 2016 Ecofin Water & Power Opportunities PLC and its affiliates controlled approximately 58.8% of the combined voting power of our common stock and its designees hold two of the seats on our board of directors. As a result, Ecofin Water & Power Opportunities PLC will the ability to elect all of the members of our board of directors and to control our management and affairs. In addition, it may be able to determine the outcome of all matters requiring stockholder approval, including mergers and other material transactions, and are able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company and might ultimately affect the market price of our common stock.

We are a “controlled company” within the meaning of Nasdaq listing standards and, as a result, qualify for, and rely on, exemptions from certain corporate governance requirements. You will not have the same protections afforded to stockholders of companies that are subject to such requirements.

We are a “controlled company” within the meaning of Nasdaq listing standards. Under these rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements of Nasdaq, including (i) the requirement that a majority of the board of directors consist of independent directors, (ii) the requirement that we have a nominating and corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities and (iii) the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. We intend to rely on some or all of these exemptions. For example, we will not have a majority of independent directors and our compensation and nominating and corporate governance committees will not consist entirely of independent directors.

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Item 2. Financial Information.

	Three Months Ended March 31,						Year ended December 31,
($ in thousands except shares and per share amounts)	2016			2015			2015			2014
	(unaudited)			(unaudited)
Statement of Operations Data:
Revenues
Oil sales	$	8,951		$	16,221		$	70,739		$	104,233
Natural gas sales	1,622			1,327			6,823			7,590
Natural gas liquid sales	624			514			1,928			3,804
Total revenue	11,197			18,062			79,490			115,627
Operating expenses
Lease operating and gas gathering	4,673			3,461			17,854			16,632
Production, ad valorem and severance taxes	916			1,351			4,982			7,123
Depletion, depreciation and amortization	15,139			12,785			58,828			40,522
Accretion of asset retirement obligations	56			52			214			201
Impairment of oil and gas properties	—			—			28,623			5,478
Stock-based compensation	95			433			2,585			1,939
General and administrative	2,773			2,289			10,824			8,913
Total operating expenses	23,652			20,371			123,910			80,808
Income (loss) from operations	(12,455		)	(2,309		)	(44,420		)	34,819
Other income (expense)
Interest expense	(6,125		)	(5,847		)	(24,577		)	(19,949		)
Gains (losses) on commodity derivatives	1,716			6,975			27,608			43,972
Other income (expense)	(228		)	(664		)	(1,065		)	55
Total other income (expense)	(4,637		)	464			1,966			24,078
Income (loss) before taxes	(17,092		)	(1,845		)	(42,454		)	58,897
Income tax benefit (expense)	5,795			1,120			15,121			(22,431		)
Net income (loss)	$	(11,297	)	$	(725	)	$	(27,333	)	$	36,466
Pro forma weighted average number of common shares outstanding
Basic(1)	7,522,025			7,522,025			7,522,025			7,330,602
Diluted(1)	7,522,025			7,522,025			7,522,025			7,534,805
Pro forma net earnings per common share
Basic(1)	$	(1.50	)	$	(0.10	)	$	(3.63	)	$	4.97
Diluted(1)	$	(1.50	)	$	(0.10	)	$	(3.63	)	$	4.84
Balance Sheet Data:
Cash and cash equivalents	$	4,188		$	3,596		$	4,321		$	9,992
Oil and gas properties	489,752			494,125			488,100			481,079
Total assets	531,862			555,450			541,521			559,069
Long-term debt	301,263			274,626			303,711			264,614
Stockholders’ equity	171,766			207,423			182,966			207,702

(1) Gives effect to the Reorganization and the 50:1 share consolidation that Lonestar Resources Limited effected in May 2015 as if they had occurred for the period indicated.

Overview

We are an independent oil and natural gas company, focused on the development, production and acquisition of unconventional oil, NGLs and natural gas properties in the Eagle Ford Shale in Texas, where we have accumulated approximately 38,242 gross (33,951 net) acres in what we believe to be the formation’s crude oil window. We also hold a portfolio of conventional, long-lived, crude oil-weighted onshore assets in Texas and are conducting resource evaluation on approximately 44,084 gross (28,655 net) acres in the West Poplar area of the Bakken-Three Forks trend in Roosevelt County, Montana.

As we have increased our focus on the Eagle Ford Shale over the past three years, our properties have changed. In particular:

· in 2013, we sold our conventional properties in Louisiana and Oklahoma;

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· also in 2013, we sold our Barnett Shale assets (with all production being natural gas) for a cash price of $10.0 million;

· in March 2014, we acquired certain oil and natural gas interests, comprising 15,232 gross (13,156 net) acres, in the Eagle Ford Shale for $70.8 million in cash; and

· in May 2015, we acquired leasehold associated with approximately 6,122 gross (4,047 net) acres in the Eagle Ford Shale, including 1,720 gross (1,225 net) acres for $2.1 million and 4,402 gross (2,822 net) acres through a farm-in agreement.

How We Conduct Our Business and Evaluate Our Operations

We employ our capital resources for exploration, acquisitions and development in what we believe to be the most attractive opportunities available to us as market conditions evolve. We have historically acquired properties that we believe have significant appreciation potential through exploration, development, production optimization or cost reduction. We intend to continue to focus our efforts on the acquisition of operated properties to the extent we believe they meet our return objectives.

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

· production volumes;

· realized prices on the sale of oil and natural gas, including the effect of our commodity derivative contracts;

· lease operating and production expenses;

· general and administrative expenses; and

· EBITDAX (as defined below).

Production Volumes

Production volumes directly impact our results of operations. Based on the expected timing of our drilling schedule and decline curves, we determine our oil and natural gas production budgets and forecasts. We assess our actual production performance by comparing oil and natural gas production at a prospect level to budgets, forecasts and prior periods. In addition, we compare our initial production rates to our peers in each of our operated prospects.

Realized Prices on the Sale of Oil and Natural Gas

Factors Affecting the Sales Price of Oil and Natural Gas. We expect to market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as geopolitical events, economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.

Oil. The New York Mercantile Exchange — West Texas Intermediate (“NYMEX-WTI”) futures price is a widely used benchmark in the pricing of domestic crude oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that oil differs in its molecular makeup, which plays an important part in refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (i) the American Petroleum Institute (“API”) gravity of the oil; and (ii) the percentage of sulfur content by weight of the oil. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore,

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depending on supply and demand fundamentals, normally sell at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur content oil (“sour” oil).

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the proximity to the major consuming and refining markets. Oil that is produced close to major consuming and refining markets is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).

Oil prices have historically been extremely volatile, and we expect this volatility to continue. For example, the NYMEX-WTI oil price ranged from a high of $ 107.95 per Bbl to a low of $53.45 per Bbl during the year ended December 31, 2014 and from a high of $61.36 per Bbl to a low of $34.55 per Bbl during the year ended December 31, 2015. Our realized price per Bbl varies by basin and is based upon transportation costs, mainly trucking costs and pipeline tariffs, and regional basis differentials.

Natural Gas. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (i) the Btu content of natural gas, which measures its heating value; and (ii) the percentage of sulfur, CO2 and other inert content by volume. Wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO2 content sells at a premium to natural gas with high sulfur and CO2 content because of the added cost to separate the sulfur and CO2 from the natural gas to render it marketable. Wet natural gas is processed in third-party natural gas plants, and residue natural gas as well as NGLs are recovered and sold. Dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the proximity to the major consuming markets. The processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds also affects the differential. Generally, these index prices have historically been at a discount to NYMEX-Henry Hub natural gas prices.

Natural gas prices have historically been extremely volatile, and we expect this volatility to continue. For example, the NYMEX-Henry Hub natural gas price ranged from a high of $8.15 per MMBtu to a low of $ 2.74 per MMBtu during the year ended December 31, 2014 and from a high of $3.32 per MMBtu to a low of $1.63 per MMBtu during the year ended December 31, 2015. Our realized gas price per MMBtu varies by basin based upon transportation costs, mainly pipeline tariffs, as well as liquids premiums and regional basis differentials.

Commodity Derivative Contracts. We have adopted a commodity derivative policy designed to minimize volatility in our cash flows from changes in commodity prices. Should we reduce our estimates of future production to amounts that are lower than our commodity derivative volumes, we will reduce our positions as soon as practical. Our credit facility prohibits us from entering into hedging arrangements for more than 90% of our projected production of crude oil and natural gas.

Lease Operating Expenses

We strive to increase our production levels to maximize our revenue. We evaluate operating costs to determine reserves, rates of return, and current and long-term profitability of our wells. We expect expenses for utilities, direct labor, water injection and disposal, and materials and supplies to

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comprise the most significant portion of our oil and natural gas production expenses. Oil and natural gas production expenses do not include general and administrative costs or production and other taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities may result in increased oil and natural gas production expenses during periods the repairs are performed.

A majority of our operating cost components are variable and may increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production-related activities, such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production. Over the life of hydrocarbon fields, the amount of water produced may increase and, as pressure declines in natural gas wells that also produce water, more power will be needed for artificial lift systems that help to remove water produced from the wells. Thus, production of a given volume of hydrocarbons may become more expensive each year as the cumulative oil and natural gas produced from a field increases until additional production becomes uneconomic. Our lease operating and production expense are both included in lease operating expenses.

Severance and Ad Valorem Taxes

The State of Texas regulates the development, production, gathering and sale of oil and natural gas, including imposing production taxes. The state currently imposes a production tax equal to 4.6% of the market value of oil sold, and a regulatory fee and tax of 0.8125% per barrel of oil sold. The State of Texas also imposes a production tax equal to 7.5% of the market value of the natural gas sold, and a regulatory fee of 0.0667% per Mcf of gas sold.

Generally, production taxes include taxes calculated on production volumes and sales values. Severance taxes are calculated on asset values at the beginning of each calendar year.

General and Administrative Expenses

General and administrative expenses are comprised of employee benefits expense (including salaries and wages) and administrative expenses. Employee benefits expense includes salaries, wages and related benefits for our corporate personnel. Stock compensation, including stock options, are expensed in the statement of operations over their vesting period. The total amount expensed over the vesting period is determined by reference to the fair value of the options and restricted share units at the grant date. Administrative expenses include overhead costs, such as maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services, and legal compliance.

EBITDAX

EBITDAX is a supplemental, non-GAAP measure and is defined as our earnings before interest expense, income taxes, depreciation, depletion and amortization, property impairments, gain (loss) on sale of non-current assets, exploration expense, share-based compensation and income and gains and losses on commodity hedging net of settlements of commodity hedging. We use this non-GAAP measure primarily to compare our results with other companies in the industry that make a similar disclosure. We note, however, because EBITDAX is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies.

Outlook

During the third and fourth quarters of 2015, benchmark crude oil prices declined dramatically and benchmark natural gas prices softened. As a result of the price declines, the Company recorded impairment on its oil and gas properties at December 31, 2015 of approximately $28.6 million. If pricing continues to decline, it is reasonably likely that the Company may have to record additional impairment subsequent to December 31, 2015.

We believe that oil and natural gas prices will remain volatile for the foreseeable future. During 2015, we modified our drilling and completion program to both maximize returns as well as take advantage of new drilling opportunities. Our reserve report dated December 31, 2014 included 62.0 gross / 57.6 net Proved Undeveloped drilling locations, of which 18.0 gross / 15.9 net locations were scheduled for 2015. As of December 31, 2015, we drilled 14.0 gross / 12.4 net wells scheduled for 2015, and completed 12.0 gross / 10.4 net wells. We redirected drilling capital away from 4.0 gross / 3.5 net proved undeveloped drilling locations, which are held by production, in favor of drilling 4.0 gross / 2.3 net farm-in wells that allowed us to earn working interests in new leaseholds. Our reserve report dated December 31, 2015 includes a total of 62.0 gross / 57.3 net proved undeveloped locations, all of which are scheduled prior to December 31, 2020.

In 2016, we plan to invest substantially all of our capital budget in the horizontal development of our Eagle Ford Shale properties, on which we currently expect to allocate between $35 million and $45 million to Eagle Ford Shale drilling and completion activities. We believe that cash flow from operations will fund this program.

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Operating Results

The following discussion relates to our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our consolidated financial statements and the notes thereto. Comparative results of operations for the period indicated are discussed below.

Results of operations for the three months ended March 31, 2016 compared to the three months ended March 31, 2015

Net Production

	For the three months ended March 31,
	2016	2015	% Change
Crude Oil (Bbls/d):
Eagle Ford Shale	3,066	3,644	-16	%
Conventional	348	400	-13	%
Total Crude Oil	3,414	4,043	-16	%
Natural Gas Liquids (Bbls/d):
Eagle Ford Shale	1,390	532	161	%
Conventional	14	10	25	%
Total NGLs	1,404	542	159	%
Natural Gas (Mcf/d):
Eagle Ford Shale	8,987	3,909	130	%
Conventional	1,424	1,861	-23	%
Total Natural Gas	10,411	5,770	80	%
Oil Equivalent (Boe/d):
Eagle Ford Shale	5,954	4,827	23	%
Conventional	599	720	-17	%
Total Oil Equivalent	6,553	5,547	18	%

Our production increased 18% from an average of 5,547 Boe/d during the three months ended March 31, 2015 to an average of 6,553 Boe/d during the three months ended March 31, 2016. The increase in our average daily production is the result of an effective drilling program. For the three months ended March 31, 2016, approximately 52% of our production was crude oil, 21% was NGLs and 27% was natural gas.

· Net production from our Eagle Ford Shale assets averaged approximately 5,954 Boe/d in the three months ended March 31, 2016, a 23% increase over the approximate 4,827 Boe/d in in the three months ended March 31, 2015. Approximately 75% of our Eagle Ford production in the three months ended March 31, 2016 was liquid hydrocarbons.

· Net production from our conventional properties decreased 17% from 720 Boe/d in the three months ended March 31, 2015 to 599 Boe/d in the three months ended March 31, 2016. Approximately 60% of our production from our Conventional properties during the three months ended March 31, 2016 was liquid hydrocarbons.

· As we seek to more closely align cash flow with capital spending, we expect production growth to moderate considerably. With our capital plans, we would expect 2016 production to grow no more than 10% over 2015 production levels.

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Average Sales Price

	For the three months ended March 31,
	2016		2015		% Change
Crude Oil ($/Bbls):
Eagle Ford Shale	$	28.88	$	44.36	-35	%
Conventional	28.21		46.49		-39	%
Total Crude Oil	$	28.81	$	44.58	-35	%
Natural Gas Liquids ($/Bbls):
Eagle Ford Shale	$	4.89	$	10.41	-53	%
Conventional	5.95		15.74		-62	%
Total NGLs	$	4.90	$	10.52	-53	%
Natural Gas ($/Mcf):
Eagle Ford Shale	$	1.70	$	2.46	-31	%
Conventional	1.78		2.76		-36	%
Total Natural Gas	$	1.71	$	2.56	-33	%
Oil Equivalent ($/Boe):
Eagle Ford Shale	$	18.58	$	36.63	-49	%
Conventional	20.77		33.17		-37	%
Total Oil Equivalent, excluding the effect from hedging	$	18.78	$	36.18	-48	%
Total Oil Equivalent, including the effect from hedging	$	35.79	$	57.69	-38	%

The average wellhead price for our production in the three months ended March 31, 2016 was $ 18.78 per Boe, which was 48% lower than the average price in the comparable period in 2015. Reported wellhead realizations were driven lower by significant declines (30 - 50%) in both the crude oil and natural gas benchmarks between the periods. While benchmark prices fell sharply, our revenues were bolstered by crude oil hedge positions, which added $32.66 per barrel to crude oil price realization.

· The average wellhead price for our Eagle Ford Shale production in the three months ended March 31, 2016 was $18.58 per Boe, which was 48% lower than the average price in the comparable period in 2015 due to the significant decline in the crude oil and natural gas benchmarks.

· The average wellhead price for our Conventional properties in the three months ended March 31, 2016 was $20.77 per Boe, which was 37% lower than the average price in the comparable period in 2015 due to the significant decline in WTI pricing.

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Revenues

	For the three months ended March 31,
($ in millions)	2016		2015		% Change
Oil Revenues:
Eagle Ford Shale	$	8.1	$	14.5	-45	%
Conventional	0.9		1.7		-47	%
Total Oil Revenues	$	9.0	$	16.2	-45	%
NGLs Revenues:
Eagle Ford Shale	$	0.6	$	0.5	24	%
Conventional	0.0		0.0		-52	%
Total NGLs Revenues	$	0.6	$	0.5	22	%
Natural Gas Revenues:
Eagle Ford Shale	$	1.4	$	0.9	61	%
Conventional	0.2		0.5		-50	%
Total Natural Gas Revenues	$	1.6	1.4		22	%
Total Wellhead Revenues:
Eagle Ford Shale	$	10.1	$	15.9	-37	%
Conventional	1.1		2.2		-47	%
Total Wellhead Revenues	$	11.2	$	18.1	-38	%

While wellhead revenue declined $ 6.9 million (38%) in the three months ended March 31, 2016 compared to the comparable period in 2015 due to the significant decrease in benchmark prices, we realized a favorable crude oil hedge, which added $10.1 million in gains on commodity derivatives for the three months ended March 31, 2016.

· Wellhead revenues for our Eagle Ford Shale assets decreased $5.8 million (37%) in the three months ended March 31, 2016 from the comparable period in 2015 as a result of a 49% decrease in wellhead price realizations but partially offset by a 23% increase in production in the three months ended March 31, 2016.

· Wellhead revenues for our Conventional properties decreased $1.0 million (47%) in the three months ended March 31, 2016 from the comparable period in 2015 as a result of a 37% decrease in wellhead price realizations.

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Operating Costs and Expenses

The table below presents a detail of expenses for the periods indicated.

	Three months ended March 31				%
	2016		2015		Change
Lease Operating Expense ($/Boe):
Western Eagle Ford Shale	$	6.26	$	6.52	-4	%
Central Eagle Ford Shale	8.39		5.68		48	%
Eastern Eagle Ford Shale	10.68		4.94		116	%
Conventional	12.76		12.68		1	%
Total lease operating expenses ($/Boe)	$	7.32	$	6.93	6	%
Production Taxes ($/Boe):
Western Eagle Ford Shale	$	1.29	$	2.37	-45	%
Central Eagle Ford Shale	1.75		3.58		-51	%
Eastern Eagle Ford Shale	2.87		2.68		7	%
Conventional	2.45		2.79		-12	%
Total production taxes ($/Boe)	$	1.53	$	2.71	-43	%

Lease Operating Expenses

Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production or ad valorem taxes.

Our total lease operating expenses increased $ 0.9 million (26%) in the three months ended March 31, 2016 from the comparable period in 2015 primarily due to the increase in production during Q1 2016 vs. Q1 2015. On a units-of-production basis, our lease operating expenses increased 6% from $6.93 per Boe in the three months ended March 31, 2015 to $7.32 per Boe in the three months ended March 31, 2016.

Severance and Ad Valorem Taxes

Severance and ad valorem taxes are paid on produced crude oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.

Our total production and ad valorem taxes declined $0.4 million (32%) in the three months ended March 31, 2016 from the comparable period in 2015 principally due to the 38% decline in wellhead revenues.

Depreciation, Depletion and Amortization (DD&A)

Capitalized costs attributed to our proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and natural gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years.

DD&A increased $2.4 million (18.4%) in the three months ended March 31, 2016 from the comparable period in 2015 primarily due to the 18% increase in total oil equivalent produced in the three months ended March 31, 2016.

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Results of operations for the year ended December 31, 2015 compared to the year ended December 31, 2014

Net Production

	For the year ended December 31,
	2015	2014	% Change
Crude Oil (Bbls/d):
Eagle Ford Shale	3,843	2,833	36	%
Conventional	373	434	-14	%
Total Crude Oil	4,216	3,267	29	%
Natural Gas Liquids (Bbls/d):
Eagle Ford Shale	864	423	104	%
Conventional	13	13	3	%
Total NGLs	877	436	101	%
Natural Gas (Mcf/d):
Eagle Ford Shale	6,224	3,277	90	%
Conventional	1,662	1,387	20	%
Total Natural Gas	7,887	4,664	69	%
Oil Equivalent (Boe/d):
Eagle Ford Shale	5,744	3,802	51	%
Conventional	663	678	-2	%
Total Oil Equivalent	6,407	4,480	43	%

Our production increased 43% from an average of 4,480 Boe/d during the year ended December 31, 2014 to an average of 6,407 Boe/d during the year ended December 31, 2015. The increase in our average daily production is the result of an effective drilling program. For the year ended December 31, 2015, approximately 66% of our production was crude oil, 14% was NGLs and 20% was natural gas.

· Net production from our Eagle Ford Shale assets averaged approximately 5,744 Boe/d in the year ended December 31, 2015, a 51% increase over the approximate 3,802 Boe/d in in the year ended December 31, 2014. Approximately 79% of our Eagle Ford production in the year ended December 31, 2015 was liquid hydrocarbons.

· Net production from our conventional properties decreased 2% from 679 Boe/d in the year ended December 31, 2014 to 664 Boe/d in the year ended December 31, 2015. Approximately 58% of our production from our Conventional properties during the year ended December 31, 2015 was liquid hydrocarbons.

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Average Sales Price

	For the year ended December 31,
	2015		2014		% Change
Crude Oil ($/Bbls):
Eagle Ford Shale	$	45.96	$	87.34	-47	%
Conventional	45.61		87.89		-48	%
Total Crude Oil	$	45.93	$	87.41	-47	%
Natural Gas Liquids ($/Bbls):
Eagle Ford Shale	$	12.56	$	29.08	-57	%
Conventional	18.87		35.06		-46	%
Total NGLs	$	12.66	$	29.26	-57	%
Natural Gas ($/Mcf):
Eagle Ford Shale	$	2.30	$	4.04	-43	%
Conventional	2.71		5.59		-52	%
Total Natural Gas	$	2.39	$	4.50	-47	%
Oil Equivalent ($/Boe):
Eagle Ford Shale	$	35.13	$	71.78	-51	%
Conventional	32.82		68.37		-52	%
Total Oil Equivalent, excluding the effect from hedging	$	34.89	$	71.27	-51	%
Total Oil Equivalent, including the effect from hedging	$	50.43	$	72.01	-30	%

The average wellhead price for our production in the year ended December 31, 2015 was $ 34.89 per Boe, which was 51% lower than the average price in the comparable period in 2014. Reported wellhead realizations were driven lower by significant declines (30 - 50%) in both the crude oil and natural gas benchmarks between the periods. While benchmark prices fell sharply, our revenues were bolstered by crude oil hedge positions, which added $23.61 per barrel to crude oil price realization.

· The average wellhead price for our Eagle Ford Shale production in the year ended December 31, 2015 was $35.13 per Boe, which was 51% lower than the average price in the comparable period in 2014 due to the significant decline in the crude oil and natural gas benchmarks.

· The average wellhead price for our Conventional properties in the year ended December 31, 2015 was $32.82 per Boe, which was 52% lower than the average price in the comparable period in 2014 due to the significant decline in WTI pricing.

Revenues

	For the year ended December 31,
($ in millions)	2015		2014		% Change
Oil Revenues:
Eagle Ford Shale	$	64.5	$	90.3	-29	%
Conventional	6.2		13.9		-55	%
Total Oil Revenues	$	70.7	$	104.2	-32	%
NGLs Revenues:
Eagle Ford Shale	$	1.9	$	3.7	-49	%
Conventional	.1		.1		—	%
Total NGLs Revenues	$	2.0	$	3.8	-47	%
Natural Gas Revenues:
Eagle Ford Shale	$	5.2	$	4.8	8	%
Conventional	1.6		2.8		-43	%
Total Natural Gas Revenues	$	6.8	7.6		-11	%
Total Wellhead Revenues:
Eagle Ford Shale	$	71.6	$	98.8	-28	%
Conventional	7.9		16.8		-53	%
Total Wellhead Revenues	$	79.5	$	115.6	-31	%

While wellhead revenue declined $36.1 million (31%) in the year ended December 31, 2015 compared to the comparable period in 2014 due to the significant decrease in benchmark prices, we realized a favorable crude oil hedge, which added $36.3 million in gains on commodity derivatives for the year ended December 31, 2015.

· Wellhead revenues for our Eagle Ford Shale assets decreased $27.2 million (28%) in the year ended December 31, 2015 from the comparable period in 2014 as a result of

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a 50% decrease in wellhead price realizations but partially offset by a 51% increase in production in the year ended December 31, 2015.

· Wellhead revenues for our Conventional properties decreased $8.9 million (53%) in the year ended December 31, 2015 from the comparable period in 2014 as a result of a 55% decrease in wellhead price realizations.

Operating Costs and Expenses

The table below presents a detail of expenses for the periods indicated.

	Year ended December				%
	2015		2014		Change
Lease Operating Expense ($/Boe):
Western Eagle Ford Shale	$	7.25	$	8.26	-12	%
Central Eagle Ford Shale	7.29		9.59		-24	%
Eastern Eagle Ford Shale	6.96		4.85		43	%
Conventional	14.61		18.12		-19	%
Total lease operating expenses ($/Boe)	$	7.99	$	9.60	-17	%
Production Taxes ($/Boe):
Western Eagle Ford Shale	$	1.88	$	4.07	-54	%
Central Eagle Ford Shale	2.61		4.47		-42	%
Eastern Eagle Ford Shale	2.45		4.36		-44	%
Conventional	2.64		5.41		-51	%
Total production taxes ($/Boe)	$	2.13	$	4.36	-51	%

Lease Operating Expenses

Our total lease operating expenses increased slightly in the year ended December 31, 2015 from the comparable period in 2014 as we controlled costs. Costs were controlled by developing experienced field staff, by upgrading our preventative maintenance activities and by more effective use and centralized purchasing of chemicals, among other activities. On a units-of-production basis, our lease operating expenses declined 17% from $9.60 per Boe in the year ended December 31, 201 4 to $7.99 per Boe in the year ended December 31, 2015. While lease operating expenses remained virtually unchanged in absolute dollar terms, given the increase in production, lease operating expenses on a units-of-production basis dropped significantly.

Severance and Ad Valorem Taxes

Our total production and ad valorem taxes declined $2.1 million (30%) in the year ended December 31, 2015 from the comparable period in 2014 principally due to the 30% decline in wellhead revenues.

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Depreciation, Depletion and Amortization (DD&A)

DD&A increased $18.3 million (45%) in the year ended December 31, 2015 from the comparable period in 2014 primarily due to the 43% increase in total oil equivalent produced in the year ended December 31, 2015.

General and Administrative (G&A) Expenses

G&A increased $1.9 million (21%) in the year ended December 31, 2015 from the comparable period in 2014 primarily due to the general and administrative expenses necessary to support higher production. Included in the 2015 G&A expense was approximately $1.0 million of legal and audit expenses associated with the company’s efforts to re-domicile to the United States, and list on the Nasdaq Stock Market. As we scale the business, we achieved a 22% decrease in G&A per Boe to $4.00 per Boe in the year ended December 31, 2015 from $5.15 per Boe in the year ended December 31, 2014.

Interest Expense

Our interest expense increased $4.6 million (23%) in the year ended December 31, 2015 from the comparable period in 2014 primarily due to (i) interest on our 8.750% Senior Notes due 2019, which were issued in April 2014, accruing the entire year for 2015 but only partially during the year ended December 31, 2014 and (ii) a non-cash write-off of approximately $0.7 million of deferred financing costs associated with the extinguishment of our previous credit facility that was replaced by a Citibank-led facility in July 2015.

Net borrowings under our credit facilities averaged $ 78.9 million in the year ended December 31, 2015 and the weighted average interest rate on outstanding borrowings was 2.6% during the year. Net borrowings under our credit facilities averaged $43 million in the year ended December 31, 2014 and the weighted average interest rate on outstanding borrowings was 2.95% during the year.

Commodity Derivative Transactions

We apply mark-to-market accounting to our derivative contracts. In the year ended December 31, 2015, we recognized a non-cash $ 8.7 million loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $36.3 million realized gain on settlement of our commodity derivative contracts. Settlement of the crude oil hedge positions added $23.61 per barrel to crude oil price realization. The crude oil hedge positions settled covered 64% of total crude oil production for the year ended December 31, 2015, and provided a $37.01 positive delta to benchmark pricing based on our weighted average hedge contract price of $85.87.

In the year ended December 31, 2014, we recognized a non-cash $42.8 million gain on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $1.2 million realized gain on settlement of our commodity derivative contracts. The crude oil hedge positions settled covered 74% of total crude oil production for the year ended December 31, 2014, and provided a $1.44 positive delta to benchmark pricing based on our weighted average hedge contract price of $95.58.

Income Taxes

As a result of the net loss before income tax of $42.5 million in 2015 and net income before tax of $58.9 million in 2014, we recorded income tax benefit of $15.1 million in 2015 and an income tax expense of $22.4 million in 2014.

Net Income (Loss) Before Taxes

As a result of the above factors, and particularly the $36.1 million (31%) decrease in revenue resulting from the decline in crude oil and natural gas benchmark prices, we recorded a net loss before income tax of $42.5 million in the year ended December 31, 2015 compared to net income of $58.9 million in the year ended December 31, 2014.

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Sources of Liquidity and Capital Resources

We expect that our primary sources of liquidity and capital resources will be cash flows generated by operating activities and borrowings under our revolving credit facility.

We have historically financed our acquisition and development activity through cash flows generated by operating activities, borrowings under our revolving credit facility, and the issuance of bonds.

Historical Cash Flows

The following table summarizes our cash flows for the periods indicated:

	For the three months end March 31,				For the year ended December 31,
($ in millions)	2016		2015		2015			2014

Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	17.7		7.8		$	50.9		$	82.2
Investing activities	(16.8	)	(26.2	)	(94.5		)	(233.0		)
Financing activities	(1.0	)	12.0		38.0			154.5
Effect of exchange rate changes on cash and cash equivalents	—		—		—			(0.4		)
Increase (decrease) in cash and cash equivalents	(0.1	)	(6.4	)	$	(5.6	)	$	3.3

Net Cash Provided By Operating Activities

Net cash provided by operating activities increased $9.9 million from $7.8 million in the three months ended March 31, 2015 to $17.7 million in the three months ended March 31, 2016. This increase is primarily due to a $10.6 million increase in net loss and a $4.7 million decrease in deferred taxes offset by, offset by a $17.5 million increase in net operating assets and liabilities, a $2.4 million increase in DD&A and a $5.3 million decrease in in gain on derivative financial instruments during the three months ended March 31, 2016.

Net cash provided by operating activities decreased $31.3 million from $82.2 million in the year ended December 31, 2014 to $50.9 million in the year ended December 31, 2015. This decrease is primarily due to a $63.8 million decline in net income (resulting in a net loss of $27.3 million) and a $26.0 million decrease in net operating assets and liabilities, offset by an $18.3 million increase in DD&A. We also experienced a $16.4 million increase in gain on derivative financial instruments and an increase of $23.1 million in impairment of oil and gas properties.

Net Cash Used In Investing Activities

Net cash used in investing activities decreased $9.4 million from $26.2 million in the three months ended March 31, 2015 to $16.8 million in the three months ended March 31, 2016. This decrease is primarily due to (i) a $1.1 million decrease in the acquisition of oil and gas properties and (ii) an $8.4 million decrease in the development of oil and gas properties.

Net cash used in investing activities decreased $138.5 million from $233.0 million in the year ended December 31, 2014 to $94.5 million in the year ended December 31, 2015. This decrease is primarily due to (i) a $62.3 million decrease in the acquisition of oil and gas properties and (ii) a $78.7 million decrease in the development of oil and gas properties, partially offset by a decrease of $3.2 million in proceeds from the sale of oil and gas properties.

Net Cash Provided By Financing Activities

Net cash used in financing activities increased $13.0 million from $12.0 million provided during the three months ended March 31, 2015 to $1.0 million used in the three months ended March 31, 2016. The decrease was due to payment on bank borrowings exceeding proceeds from bank borrowings by $1.0 million in the three months ended March 31, 2016. During the three months ended March 31, 2015 the Company reported borrowings of $12.0 million.

Net cash provided by financing activities decreased $116.5 million from $154.5 million in the year ended December 31, 2014 to $38.0 million in the year ended December 31,

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2015. The decrease was principally due to the receipt of $214.5 million from the sale of 8.750% Senior Notes due 2019 in 2014, partially offset by a net change in bank borrowings of $98.0 million.

Debt

As of March 31, 2016, we had an aggregate of $301.0 million of indebtedness, including $86.0 million drawn on our revolving credit facility and $220.0 million (less an unamortized discount of $3.3 million and debt issuance costs of $1.7 million) under our 8.750% Senior Notes due 2019.

Revolving Credit Facility

LRAI and its subsidiaries have entered into a revolving credit facility with Citibank, N.A. as Administrative Agent, and certain other lenders. The revolving credit facility matures on October 16, 2018.

As of March 31, 2016, we had outstanding borrowings of approximately $86.0 million under the revolving credit facility, which was subject to an average interest rate of approximately 2.75% during the three months ended March 31, 2016. Additionally, the revolving credit facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. We have drawn $300,000 of advances on the letter of credit as of March 31, 2016. Availability under our revolving credit facility was $94 million as of March 31, 2016 with a borrowing base of $180.0 million. The borrowing base under our revolving credit facility can be redetermined up or down by the lenders based on, among other things, their evaluation of our oil and natural gas reserves. Effective May 19, 2016, we received notification that the borrowing base was reduced to $120 million. Also, redeterminations are now scheduled semi-annually to occur on May 1 and November 1 of each year. The next borrowing base redetermination is scheduled for November 1, 2016. An amendment to the credit agreement governing our credit facility was executed during May 2016 to document these changes. Our current 2016 capital budget calls for spending from between $35 and $45 million, which we believe can be funded from cash flow, and leaves us a continued cushion in the form of undrawn borrowing under the facility, albeit reduced. In addition, we have had preliminary discussions with third parties regarding the sale of our conventional assets in Texas. While there is no assurance that we will be successful in selling our conventional assets on terms acceptable to us or at all, we believe that such a sale would increase our liquidity.

Obligations under the revolving credit facility are secured by a first priority lien on substantially all assets of the existing and future subsidiaries of LRAI, including a first priority lien on all ownership interests in its existing and future subsidiaries. Obligations under the revolving credit facility are guaranteed by all its existing and future subsidiaries.

At the election of LRAI, borrowings under the revolving credit facility may be made on an alternate base rate or an adjusted eurodollar rate basis, plus an applicable margin. The applicable margin varies from 0.75% to 1.75% for alternate base rate borrowings and from 1.75% to 2.75% for eurodollar borrowings, depending on the utilization of the borrowing base. LRAI is also required to pay a commitment fee on the unused committed amount at a rate equal to 0.375% to 0.50% per annum.

The revolving credit facility contains various affirmative and negative covenants and events of default that limit an ability to incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates and hedge transactions and make certain acquisitions. The revolving credit facility also contains financial covenants that require the satisfaction of certain specified financial ratios, including (i) current assets to current liabilities of at least 1.0 to 1.0 and (ii) total debt to consolidated EBITDAX of not greater than 4.0 to 1.0. We were in compliance with our debt covenants as of March 31, 2016.

8.750% Senior Notes due 2019

LRAI issued $220 million aggregate principal amount of 8.750% Senior Notes due 2019 (the “Notes”) in April 2014 under an indenture among LRAI, its subsidiary guarantors and Wells Fargo

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Bank, National Association, as trustee (the “Trustee”). Lonestar Resources Limited is not a party to the indenture.

The Notes mature on April 15, 2019 and accrue interest at a rate of 8.750% per annum, payable semi-annually in arrears on April 15 and October 15 of each year until the maturity date. The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each subsidiary of LRAI.

LRAI may redeem up to 35% of the Notes prior to April 15, 2016 with an amount of cash not greater than the net proceeds of certain equity offerings at a price of 108.75% of the amount redeemed plus any accrued and unpaid interest. In addition, prior to April 15, 2016, it may redeem the Notes, in whole or in part, at a redemption price of 100% of the principal amount of the Notes redeemed, plus any accrued and unpaid interest to the redemption date, plus a “make-whole” premium. On or after April 15, 2016, it may redeem the Notes, in whole or in part, at certain redemption prices, plus any accrued and unpaid interest to the redemption date.

If LRAI sells certain assets and does not use the net proceeds for certain purposes specified in the indenture or if it experiences a change of control (as defined in the indenture), then it may be required to offer to purchase Notes from holders at a price equal to 101% of the principal amount, plus accrued and unpaid interest.

The Indenture contains certain covenants that restrict the ability of LRAI and its subsidiary guarantors to:

· borrow money;

· pay dividends on or repurchase capital stock;

· make certain investments;

· use assets as security in other transactions; and

· sell certain assets or enter into mergers or consolidations.

These limitations are subject to a number of exceptions and qualifications.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2015 is provided in the following table.

	Payments due by period
($ in millions)	Total		Less than 1 year		1 - 2 years		3 - 5 years		More than 5 years
Revolving credit facility(1)	$	87.0	$	—	$	—	$	87.0	$	—
8.750% Senior Notes due 2019	220.0		—		—		220.0		—
Interest on 8.750% Senior Notes due 2019	67.4		19.2		19.3		28.9		—
Drilling rig commitment	3.8		3.8		—		—		—
Office lease	2.6		0.5		0.9		0.8		0.4
Total commitments	$	380.8	$	23.5	$	20.2	$	336.7	$	0.4

(1) These amounts do not include any estimated interest on these borrowings, because our revolving borrowings have short-term interest periods, and we are unable to determine what our borrowing costs may be in future periods.

Capital Expenditures

Historical capital expenditures

The table below summarizes our capital expenditures incurred in the years ended December 31, 2015, 2014 and 2013.

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	Three Months Ended March 31, 2016		Year ended December 31,
($ in millions)	(unaudited)		2015		2014
Acquisition of oil and gas properties	2.1		8.7		71.0
Development of oil and gas properties	14.5		85.5		164.2
Purchases of other property and equipment	0.2		0.3		1.0
Total capital expenditures	$	16.8	$	94.5	$	236.2

2016 capital expenditure budget

We currently expect to allocate between $35 million and $45 million under our 2016 capital program to drill and complete 10 Eagle Ford Shale wells. We consider future commodity prices when determining our development plan but many other factors are also considered. Although the magnitude of change in these collective factors within a sustained low commodity price environment is difficult to estimate, we currently expect to execute our development plan based on current conditions. 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 expect to fund our 2016 capital budget with cash flow from operations, our undrawn capacity under our revolving credit facility and funding available under our Joint Development Agreement with IOG.

The amount, timing and allocation of capital expenditures are largely discretionary and within management’s control. If crude oil, NGLs and natural gas prices decline below what we consider acceptable levels, or costs increase to levels we consider unacceptable, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Estimates

The preparation of our financial statements requires us to make estimates and judgments that can affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We analyze our estimates and judgments, including those related to oil, NGLs and natural gas revenues, oil and natural gas properties, impairment of long-lived assets, fair value of derivative instruments, asset and retirement obligations and income taxes, and we base our estimates and judgments on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may vary from our estimates. We have outlined below policies of particular importance to the portrayal of our financial position and results of operations and that require the application of significant judgment or estimates by our management.

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In addition, we note that our significant accounting policies are detailed in Note 2 to our consolidated financial statements for the year ended December 31, 2014.

Estimates of Reserve Quantities

Reserve estimates are inexact and may change as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. All reserve reports prepared by the independent third-party reserve engineers are reviewed by our senior management team, including the Chief Executive Officer and Senior Vice President-Operations. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions in reserve quantities. Reserve revisions will inherently lead to adjustments of DD&A rates. We cannot predict the types of reserve revisions that will be required in future periods. A 10% increase or decrease in our estimates of total proved reserves at December 31, 2015 would have decreased or increased our DD&A expense of proved oil and gas properties by approximately $5.2 million or 9% or $6.4 million or 11%, respectively, for the year ended December 31, 2015.

Oil and Natural Gas Properties

We use the successful efforts method of accounting to account for our oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Our policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive.

Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only.

Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors.

It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the joint operating agreement that joint interest owners in a property adopt. As an operator, we record these advance payments in other current liabilities and relieve this account when the actual expenditure is billed by us in the monthly joint interest billing statement.

On the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized.

Impairment of Long-Lived Assets

The carrying value of the oil and gas properties and other related property and equipment is periodically evaluated under the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 360, Property, Plant, and Equipment. ASC 360 requires long-lived assets and certain identifiable intangibles to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to

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recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.

Under ASC 360, the Company evaluates impairment of proved and unproved oil and gas properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows.

Derivative Financial Instruments

We use derivative financial instruments to hedge our exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap, option and costless collar contracts. The use of these instruments is subject to policies and procedures as approved by our board directors. We do not trade in derivative financial instruments for speculative purposes. None of our derivative contracts have been designated as cash flow hedges for accounting purposes. Derivative financial instruments are initially recognized at cost, if any, which approximates fair value. Subsequent to initial recognition, derivative financial instruments are recognized at fair value. The derivatives are valued on a mark-to-market valuation, and the gain or loss on re-measurement to fair value is recognized through the statement of operations. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

The counterparties to our derivative instruments are not known to be in default on their derivative positions. However, we are exposed to credit risk to the extent of nonperformance by the counterparty in the derivative contracts. We believe credit risk is minimal and do not anticipate such nonperformance by such counterparties.

Asset Retirement Obligations (ARO)

We account for asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations . ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. Under ASC 410, an asset retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheet, which is allocated to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as an expense in the accompanying consolidated statement of operations. The estimation of future costs associated with the dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirement, technological advances and other factors that are difficult to predict.

There are many variables in estimating AROs. We primarily use the remaining estimated useful life from the year-end independent third-party reserve reports in estimating when abandonment could be expected for each property based on field or industry practices. We expect to see our calculations impacted significantly if interest rates move from their current levels, as the credit-adjusted-risk-free-rate is one of the variables used on a quarterly basis. Our technical team has developed a standard cost estimate based on the historical costs, industry quotes and depth of wells. Unless we expect a well’s plugging cost to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of an inflation factor and a discount factor, could differ from actual results.

Income taxes

We follow the asset and liability method in accounting for income taxes in accordance with ASC 740, Income Taxes . 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, operating losses and tax credit carryforwards.

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these 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. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

Changes in our expectations regarding our future taxable income (which is materially impacted by volatility in commodity prices), can result in our recording of a valuation allowance against our deferred tax assets. We would record this valuation allowance when our judgment is that our existing U.S. federal net operating loss carryforwards are not, on a more-likely-than-not basis, recoverable in future years. We will continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.

We evaluate uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements.

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Quantitative and Qualitative Disclosures About Risk

We are exposed to a variety of financial market risks including interest rate, commodity prices, foreign exchange and liquidity risk. Our risk management focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. We utilize derivative financial instruments to hedge certain risk exposures. Our financial instruments consist mainly of deposits with banks, short-term investments, accounts receivable, derivative financial instruments, finance facility and payables. The main purpose of non-derivative financial instruments is to raise finance for our operations.

Financial risk management is carried out by our management. Our board of directors sets financial risk management policies and procedures to which our management is required to adhere. Our management identifies and evaluates financial risks and enters into financial risk instruments to mitigate these risk exposures in accordance with the policies and procedures outlined by our board of directors.

Interest Rate Sensitivity Analysis

As of December 31, 2015, we had $87.0 million outstanding under our revolving credit facility, which is subject to floating market rates of interest. Borrowings under our revolving credit facility bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increase in this interest rate can have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at December 31, 2015, a 100 basis point change in interest rates would change our annualized interest expense by approximately $0.9 million.

Commodity Price Risk Exposure and Management

As a result of our operations, we are exposed to commodity price risk arising from fluctuations in the prices of crude oil, NGLs and natural gas. The demand for, and prices of, crude oil, NGLs and natural gas, are dependent on a variety of factors, including supply and demand, weather conditions, the price and availability of alternative fuels, actions taken by governments and international cartels and global economic and political developments.

Our board of directors actively reviews oil and natural gas hedging on a monthly basis. Reports providing detailed analysis of our hedging activity are continually monitored. We sell our oil and natural gas on market using NYMEX market spot rates reduced for basis differentials in the basins from which we produce. We use forward contracts to manage our commodity price risk exposure.

Our primary commodity risk management objective is to reduce volatility in our cash flows. Management makes recommendations on hedging that are approved by the board of directors before implementation. We enter into hedges for oil using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our board of directors. Historically we have not sought to hedge the price of our natural gas or NGL production.

Presently, all of our hedging arrangements are concentrated with two counterparties, both of which are lenders under our revolving credit facility. If these counterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.

The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

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The following table provides a summary of our derivative contracts as of March 31, 2016:

Settlement Period	Derivative Instrument	Total Volume	Fixed Price
April - December 2016	Oil — WTI Fixed Price Swap	151,000 Bbl	84.45
April - December 2016	Oil — WTI Fixed Price Swap	224,100 Bbl	90.45
April - December 2016	Oil — WTI Fixed Price Swap	94,700 Bbl	63.20
April - December 2016	Oil — WTI Fixed Price Swap	125,900 Bbl	56.90
April - December 2017	Oil — WTI Three-way collar	365,100 Bbl	—

The three-way collars provide an effective floor of $55.25 per barrel with WTI prices between $40.00 - $60.00 per barrel but also give upside to $80.25 per barrel.

Since March 31, 2016, we have entered into additional WTI crude oil swaps covering a total of 174,550 barrels for the period of May 2016 through December 2016. The addition of these swaps increased the company’s crude oil swap coverage to a total of approximately 2,847 barrels of oil per day, or approximately 70% of our expected oil production for 2016 at an average swap price of $68.69 per barrel.

Counterparty and Customer Credit Risk

In connection with our hedging activity, we have exposure to financial institutions in the form of derivative transactions. The counterparties on our derivative instruments currently in place have investment-grade credit ratings. We expect that any future derivative transactions we enter into will be with these counterparties or our lenders under our credit facilities that will carry an investment-grade credit rating.

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. 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. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.

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Item 3. Properties.

Overview

Eagle Ford Shale Trend

Our primary operational focus is on our Eagle Ford Shale position, which as of December 31, 2015 is comprised of 38,242 gross (33,951 net) acres in seven Texas counties. The Eagle Ford Shale is an oil and natural gas producing stratigraphic horizon of sedimentary rock that extends across portions of south Texas from the Mexican border into east Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford Shale is organically rich and calcareous, in places transitioning to an organic, argillaceous lime-mudstone. The formation lies between the deeper Buda limestone and the shallower Austin Chalk formation. Its thickness generally ranges between 100 and 200 feet in the productive parts of the play, is found at depths ranging from as shallow as 4,000 feet to as deep as 13,000 feet, and in much of the deeper portions of the horizon is overpressured.

Along the entire length of the Eagle Ford Shale the structural dip of the formation is consistently down to the south with relatively few, modestly-sized structural perturbations. As a result, depth of the horizon increases consistently southwards along with the thermal maturity of the formation. Where the formation is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford Shale is more natural gas. The transition between being more oil prone and more natural gas prone includes an interval that typically produces wet gas and NGLs.

The first horizontal wells drilled specifically for the Eagle Ford Shale were drilled in 2008, leading to a discovery in La Salle County. Since then, the play has expanded significantly across a large portion of south Texas and then into east Texas.

We view our properties in the Eagle Ford Shale as being divided into three distinct regions within this play: Western Eagle Ford (comprised of Dimmit, La Salle and Frio Counties), Central Eagle Ford (comprised of Gonzales and Wilson Counties) and Eastern Eagle Ford (comprised of Brazos and Robertson Counties). As of December 31, 2015, 33,951 net acres were operated by us and 18,302 net acres were held by production, or HBP. Our Eagle Ford Shale net production for the year ended December 31, 2015 was 5,744 Boe/d, comprised of 3,843 Bbls/d of oil, 864 Bbls/d of NGLs and 6,224 Mcf/d of natural gas, from 63 gross (57 net) producing wells.

As of December 31, 2015, our Eagle Ford Shale properties had proved reserves of 38.0 MMBoe, of which 76% is crude oil and NGLs and 29% is proved developed producing, or PDP. The PV-10 of our Eagle Ford proved reserves as of December 31, 2015 was $275.9 million, and 50% of such PV-10 is PDP. See Item 1 (“Business — Our Operations — PV-10”).

We had a total of 164 gross (148 net) engineered horizontal Eagle Ford drilling locations on 28,637 of our 33,951 net Eagle Ford Shale acres as of December 31, 2015. Approximately 100% of these locations are on leases operated by us, and 62 gross (56 net) locations are currently categorized as proved undeveloped, or PUD. As of December 31, 2015, we had 5,314 additional net acres in the Eagle Ford Shale trend with surrounding industry activity to which we have not assigned locations. In furtherance of our ongoing development activities, in July 2015 we entered into a Joint Development Agreement with IOG. Pursuant to the Joint Development Agreement, IOG will fund up to $100 million to be used in drilling incremental Eagle Ford Shale wells. IOG will fund up to 90% of the initial capital for the wells drilled in the program, and we will contribute the remainder of the incremental costs. IOG will have the right to participate in the drilled wells as a non-operated working

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interest owner. As of December 31, 2015 IOG was participating in the drilling and completion of two horizontal wells in La Salle County, Texas, which were spud in October 2015.

In addition, w e have identified 10 gross (10 net) engineered locations in the Eagle Ford Shale that we expect to drill in 2016. Based on our total of 164 gross engineered drilling locations as of December 31, 2015, this would provide for approximately 16 years of drilling inventory. We plan to continue evaluating this acreage and monitoring industry activity and believe the acreage may be prospective for additional locations.

Western Eagle Ford

As of December 31, 2015, our Western Eagle Ford region was comprised of 14,440 gross (13,433 net) acres in Dimmit, La Salle and Frio Counties and includes our Asherton, Beall Ranch, Burns Ranch, and Horned Frog projects. All of this net acreage was HBP. Production in the year ended December 31, 2015 was 4,157 Boe/d, which was comprised of 2,384 Bbls/d of oil, 795 Bbls/d of NGLs and 5,873 Mcf/d of gas from 38 gross (35 net) producing wells. Prominent offset operators in this region include Chesapeake Energy, EP Energy, Anadarko Petroleum, Stonegate Production and Carrizo Oil & Gas, Inc..

As of December 31, 2015, our Western region had proved reserves of 32.6 MMBoe, of which 73% is crude oil and NGLs and 27% is PDP. The PV-10 of our Western region proved reserves as of December 31, 2015 was $220.7 million and 46% of such PV-10 is PDP. See Item 1 (“Business — Our Operations — PV-10”).

According to our 2015 reserve report, single well estimated ultimate recoveries (EUR) on our undeveloped locations range from 396 MBoe to 633 MBoe across our Western region wells, projected well costs range from $3.9 million to $6.2 million for wells with lateral lengths of 3,900 feet to 8,000 feet.

We believe we have been at the forefront of drilling, completion and production techniques in the Western Eagle Ford since we began drilling in the region in 2011. We believe our Beall Ranch #1H, #2H and #3H wells were the first horizontal wells drilled in the oil window on 500 foot well spacing. Further, all of our wells in the Western Eagle Ford have been pad drilled and, wherever possible, zipper-fracked. During the four years we have been active as an operator in the Western Eagle Ford, we have made a number of improvements to our methods for drilling, completing and producing our Eagle Ford laterals. We have significantly enhanced the amount of proppant deployed in fracture stimulation procedures, increasing proppant per foot from 964 lbs/ft in our first generation of wells to 1,500 lbs/ft in the wells we drilled in 2014. We believe we have made additional improvements to our well results by virtue of modifications we have made to post-frac shut-in times, as well as choke management, which involves flowing the wells back on smaller chokes. The most compelling evidence of the collective effect of our improved practices are the increases in EURs assigned by our independent reserve engineers, W.D. Von Gonten & Co. We have designed our perforation programs to minimize perforating larger faults so as to maximize fracturing efficacy and avoid communicating with the underlying Buda formation.

As of December 31, 2015, our Western Eagle Ford acreage had a total of 38 gross (35 net) Eagle Ford producing wells with 54 gross (49 net) engineered Eagle Ford drilling locations. 100% of these gross drilling locations are on leases that we operate. Of these locations, 50 gross (45 net) locations are categorized as PUD.

Central Eagle Ford

Our Central Eagle Ford region as of December 31, 2015 was comprised of 11,666 gross (11,181 net) acres in Wilson and Gonzales Counties, and includes our Pirate and Modern Gonzo projects. As of December 31, 2015, 100% of this acreage was operated by us. Approximately 57% of this net acreage was HBP. Production in the year ended December 31, 2015 was 1,007 Boe/d,

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which was comprised of 943 Bbls/d of oil, 35 Bbls/d of NGLs and 175 Mcf/d of natural gas from 17 gross (14 net) producing wells. Prominent offset operators in this region include Hunt Oil, Marathon Oil, McMoRan Oil & Gas and EOG Resources, Inc.

As of December 31, 2015, our acreage in the Central region had proved reserves of 1.9 MMBoe, of which 96% is crude oil and NGLs and 30% is PDP. The PV-10 of our Central region proved reserves as of December 31, 2015 was $126.0 million and 76% of such PV-10 is PDP. See Item 1 (“Business — Our Operations — PV-10”).

According to our 2015 reserve report, single well EURs range from 209 MBoe to 353 MBoe across our Central region wells. Projected well costs range from $5.5 million to $6.6 million for wells with lateral lengths of 5,000 feet to 8,000 feet.

The Eagle Ford Shale occurs at a total vertical depth of 6,700 feet to 7,900 feet across our leasehold in the Central region. The total thickness of the Eagle Ford Shale in this region ranges from 90 feet to 100 feet, with the Lower Eagle Ford exhibiting thicknesses ranging from 50 feet to 60 feet.

Based on our drilling experience and that of offset operators, we believe that success in the Central Eagle Ford area is related to a different set of factors than in other parts of the Eagle Ford Shale. The Eagle Ford Shale horizon in this area is thinner yet exhibits higher porosities, and is more prone to significant faulting than in our other leasehold positions. We emphasize utilization of 3-D seismic imaging to maximize the lateral’s interface with the Eagle Ford and avoid the Buda formation, which produces high rates of water locally. We also take care to design well paths so as to minimize intersecting large faults that may take the lateral well bore out of our target Eagle Ford zone. Additionally, we believe that perforation placement is more important than proppant volumes in successful fracture stimulations in this area. Due to the relatively high porosities in the Central region compared to our other operating regions, fracture stimulation typically requires 250,000 pounds of proppant per stage, and stages are placed at an average of 250 foot intervals. We have designed our perforation programs to minimize perforating larger faults so as to maximize fracturing efficacy and avoid communicating with the underlying Buda formation.

Our Central Eagle Ford region had a total of 17 gross (16 net) Eagle Ford producers and had a total of 78 gross (71 net) engineered Eagle Ford drilling locations as of December 31, 2015. All of these drilling locations are on leases that we operate. Of these locations, 2 gross (2 net) are currently categorized as PUD.

Eastern Eagle Ford

Our Eastern Eagle Ford region as of December 31, 2015, was comprised of 12,136 gross (9,337 net) acres in Brazos and Robertson Counties. Approximately 38% of this net acreage is HBP. Our Eastern region includes 5,475 gross (4,979) net acres, which are located within the productive limits of the Aguila Vado Eagle Ford Shale Field, and an additional 6,608 gross (4,371) net acres that are under appraisal. Production in the year ended December 31, 2015 was 579 Boe/d, which was comprised of 516 Bbls/d of oil, 33 Bbls/d of NGLs and 176 Mcf/d of natural gas from 8 gross (7.6 net) producing wells.

As of December 31, 2015, our Eastern region had proved reserves of 3.5 MMBoe, of which 94% is crude oil and NGLs and 21% is PDP. The PV-10 of our Eastern region proved reserves as of December 31, 2015 was $25.5 million and 48% of such PV-10 is PDP. See Item 1 (“Business — Our Operations — PV-10”).

According to our 2015 reserve report, single well EURs range from 374 MBoe to 474 MBoe across our Eastern Eagle Ford region wells, and projected well costs range between $6.1 million and $6.9 million for wells with lateral lengths ranging from 5,000 feet to 7,000 feet.

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The Eagle Ford Shale occurs at a total vertical depth of 7,800 feet to 8,500 feet across our leasehold in the Eastern Eagle Ford. The total thickness of the Eagle Ford zone ranges from 400 feet to 500 feet in this region, with the lower Eagle Ford exhibiting thicknesses of approximately 200 feet.

Our Eastern Eagle Ford region had a total of 8 gross (7.6 net) producing wells, and had a total of 32 gross (28 net) engineered drilling locations as of December 31, 2015. All of these drilling locations are on leases that are operated by us. Of these locations, 10 gross (9 net) locations are currently categorized as PUD.

Conventional Assets

In addition to our Eagle Ford Shale acreage, we have conventional oil and natural gas properties located in 14 counties in Texas, including long-lived reserves in the Canyon, Delaware Sand, Hackberry, Caddo, Cockfield and Jackson formations. Our average working interest in our conventional assets is approximately 74%. As of December 31, 2015, these properties contained approximately 2.2 MMBoe of estimated proved reserves, of which 79% is crude oil. Production for the year ended December 31, 2015 from our conventional assets was 664 Boe/d, approximately 56% of which was crude oil, which represented 10% of our total net production for the year. We do not plan to drill any new wells on these properties in 2016.

We are in the process of updating the evaluation of proved reserves and, once complete, we may appoint a sales agent to help explore the monetization of our conventional reserves during the first half of 2016.

West Poplar Area of Bakken-Three Forks

In a series of transactions in 2011 and 2012, we acquired approximately 50,191 gross (32,624 net) undeveloped acres in the West Poplar area of the Bakken-Three Forks trend in Roosevelt County, Montana, with an average working interest of approximately 65%. We and our partners drilled one exploratory vertical well on this acreage in July 2012, which logged oil pay in three prospective unconventional zones in the Bakken, Three Forks and Lower Lodgepole formations that comprise a horizontal drilling target at depths ranging from 120 feet to 150 feet. Upon testing, each of these zones produced light gravity crude oil ranging from 41.2 to 45.8 API gravity. These tests were achieved with simple acidization and the oil volumes were produced water-free. During 2013, we completed archeological studies across our leasehold and acquired a 3-D seismic study across our leasehold, which is currently being processed, to enhance the value of these assets. With approval from the Bureau of Land Management and Bureau of Indian Affairs, we have formed with our partners a federal unit that allows for the suspension of lease expirations pending completion of an economic well, which we are considering drilling in 2016. Furthermore, we have the option to renew or extend leased acreage designated as the West Poplar Unit.

Summary of Primary Project Areas

The following table presents summary data for each of our primary project areas as of December 31, 2015:

		Average Working		Engineered Drilling Locations(1)
	Net Acreage	Interest		Gross	Net
Western Eagle Ford	13,433	94	%	54	49
Central Eagle Ford	11,181	96	%	78	71
Eastern Eagle Ford	9,337	76	%	32	28
Total Eagle Ford	33,951	89	%	164	148
Conventional Assets	N/A	74	% (2)	—	—
West Poplar	28,655	65	%	—	—
Total	62,606	78	% (3)	—	—

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Item 4. Security Ownership of Certain Beneficial Owners and Management.

The table below sets forth certain information regarding the beneficial ownership of our common stock as of April 30, 2016 by (i) each of our named executive officers; (ii) each person who, to our knowledge, beneficially owns more than 5% of our outstanding shares; and (iii) all of our directors and executive officers as a group, after giving effect to the Reorganization.

Beneficial ownership is determined according to the rules of the SEC and generally includes any shares over which a person exercises sole or shared voting or investment power. All shares of common stock owned by such person, including shares of common stock underlying stock options that are currently exercisable or exercisable within 60 days after April 30, 2016 are deemed to be outstanding and beneficially owned by that person for the purpose of computing the ownership percentage of that person, but are not considered outstanding for the purpose of computing the percentage ownership of any other person. Except as otherwise indicated, to our knowledge, each person listed in the table below has sole voting and investment power with respect to the shares shown to be beneficially owned by such person, except to the extent that applicable law gives spouses shared authority. The address of each of our executive officers and directors listed below is c/o Lonestar Resources US Inc., 600 Bailey Avenue, Suite 200, Ft.Worth, Texas 76107.

Name	Number of Shares Beneficially Owned		Percentage of Outstanding Shares(1)
Ecofin Water & Power Opportunities PLC	4,425,452	(2)	58.8	%
Springfield Lode, Colchester Road, Chelmsford, Essex, CM2 5PW, U.K.
Named Executive Officers
Frank D. Bracken, III	280,400	(3)	1.0	%
Barry Schneider	96,525	(4)		*
Thomas H. Olle	150,996	(5)		*
Directors (other than Mr. Bracken)
Bernard Lambilliotte	4,425,452	(6)	58.8	%
Christopher Rowland, Ph.D.	62,438	(7)		*
Daniel Lockwood	8,982			*
Mitchell Wells	22,200	(8)		*
John Pinkerton	90,000	(9)		*
Robert Scott	35,600			*
Executive Officers and Directors as a group (11 persons)	5,237,983	(10)	62.4	%

* Represents beneficial ownership of less than 1% of the outstanding shares of Lonestar.

(1) Based on 7,522,025 shares of common stock issued and outstanding as of April 30, 2016, after giving effect to the Reorganization.

(2) Certain shares owned by Ecofin Water & Power Opportunities PLC are held by affiliated entities with which Ecofin Water & Power Opportunities may be deemed to share beneficial ownership. Bernard Lambilliotte is Chief Investment Officer of Ecofin Limited, a fund manager that has voting and investment control authority over the shares owned by Ecofin Water & Power Opportunities PLC, and he and his family members are beneficiaries of a trust that is the controlling shareholder of Ecofin Limited.

(3) Includes 74,371 shares and 206,029 shares that Mr. Bracken has the right to acquire pursuant to currently exercisable options.

(4) Includes 46,500 shares and 50,025 shares that Mr. Schneider has the right to acquire pursuant to currently exercisable options.

(5) Includes 32,876 shares and 118,120 shares that Mr. Olle has the right to acquire pursuant to currently exercisable options.

(6) 148,958 of these shares are pledged to a third party as security for loan, and such pledge could result in a change in beneficial ownership of the shares in certain circumstances. Mr. Lambilliotte holds his shares through an account with an entity affiliated with Ecofin Water & Power Opportunities PLC, and the shares shown as being owned by him are included in the shares shown in the table as being owned by that entity.

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Item 5. Directors and Executive Officers.

The following table sets forth the name, position and age of each of our directors and executive officers.

Name	Position	Age
Frank D. Bracken, III	Chief Executive Officer	52
Barry D. Schneider	Chief Operating Officer	53
Douglas W. Banister	Chief Financial Officer	54
Thomas H. Olle	Senior Vice President - Operations	61
Jana Payne	Vice President - Geosciences	54
Bernard Lambilliotte	Chairman	57
Daniel R. Lockwood	Director	57
Dr. Christopher Rowland	Director	60
Robert Scott	Director	67
John Pinkerton	Director	61
Mitchell Wells	Director	40

Frank D. Bracken, III is our Chief Executive Officer. Mr. Bracken has served in this positions since January 2013 and has served as a director and Chief Executive Officer of Lonestar Resources, Inc., our wholly-owned subsidiary, since January 2012. Mr. Bracken previously served as Senior Managing Director of Sunrise Securities from September 2008 to December 2011 and as Managing Director of Jefferies LLC from November 1999 to August 2008. During that time, Mr. Bracken led oil and natural gas transactions, spanning from public and private equity and debt offerings to joint ventures in the Haynesville Shale to one of the first purchases of a publicly-traded oil & gas company by a private equity firm. As Chief Financial Officer and a member of the board of directors at Gerrity Oil & Gas Corp, an NYSE-listed exploration and production company, Mr. Bracken was responsible for corporate budgeting and development, equity and debt financing in public and private offerings, and acquisitions and divestitures. Mr. Bracken holds a Bachelors of Arts degree from Yale University.

Barry D. Schneider is our Chief Operating Officer. Mr. Schneider has served in this position since May 2014. Prior to joining us, Mr. Schneider held the position of Vice President - Northern Region for Denbury Resources, Inc. from January 2012 to May 2014. Mr. Schneider was at Denbury for 15 years and held positions of increasing responsibility. After holding the positions of Vice President, Production & Operations, Mr. Schneider was promoted to Vice President-East Region in October 2009 and held that position until January 2012 when he became responsible for Denbury’s Northern Region business unit. Prior to Denbury, Mr. Schneider was employed by Wiser Oil and Conoco-Philips. Mr. Schneider received his B.S. in Natural Gas Engineering from Texas A&M - Kingsville in 1985.

Douglas W. Banister is our Chief Financial Officer. He became Chief Accounting Officer of Lonestar Resources, Inc., our wholly-owned subsidiary in August 2010. Mr. Banister is a Certified Public Accountant with 30 years of experience in finance, planning, negotiating and business development. Mr. Banister began his career in public accounting with Ernst & Young, where he served in various accountant roles between June 1984 and December 1987. Between December 1987 and April 1990, Mr. Banister served as Corporate Controller for D.R. Horton, Inc. and, between October 2004 and October 2005, served as VP of finance for Richmond American Homes. Mr. Banister holds a B.B.A. from Texas Wesleyan University with an emphasis in accounting.

Thomas H. Olle is our Senior Vice President-Operations. Mr. Olle has served in this position since August 2010. Mr. Olle has over 35 years of oil and gas industry experience in multiple facets of the business, such as reservoir management and management of unconventional resource development projects including horizontal well field development and tertiary recovery projects. Mr. Olle also has significant experience with reserve evaluation and reporting, production engineering and operations, and business development functions including acquisitions, divestitures and new ventures. During his tenure at Encore Acquisition Company, Mr. Olle served as Vice President-Strategic Solutions and also held executive positions responsible for asset management and engineering. He also served as Senior Engineering Advisor for Burlington Resources from December 1985 to March 2002 and District Reservoir Engineer for Southland Royalty Company from May 1982 to December 1985. Mr. Olle holds a Bachelors of Science in Mechanical Engineering with Highest Honors from the University of Texas in Austin.

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Jana Payne was appointed our Vice-President of Geosciences in November 2015, bringing over 25 years of experience in the oil and gas industry. Prior to joining us, Ms. Payne held the position of Senior Exploitation Manager and Geologist at Halcon Resources, Inc. from November 2012 to May 2015. Ms. Payne spent eight years at Petrohawk Energy Inc. from June 2004 to October 2012 (and subsequently BHP Billiton following its acquisition of Petrohawk) as Geologic Manager and Senior Geologist, where her initial mapping of the Eagle Ford shale led to the discovery of the first commercial Eagle Ford Shale well and acquisition of over 300,000 acres by the company. Ms. Payne’s early career was as a geologist at Marathon Oil Co. and Petroleum Geo-Services, Inc. Ms. Payne has published works in learned journals and holds an MSc and BSc in geology from the University of Texas at Arlington.

Bernard Lambilliotte has served as a Director since January 2013 and Chairman of the Board since May 2014. Mr. Lambilliotte has served as Chief Investment Officer of Ecofin Limited, a specialist fund manager in equity, utilities and infrastructure, since 1992. Mr. Lambilliotte served as an investment manager with Pictet & Cie., private bankers, in Geneva and London, where he was responsible for the development of sector funds, having previously been an investment banker with Swiss Bank Corporation in London and Paris, and with Drexel Burnham Lambert in London. He sits on the board of directors of each of Hamon er Cie S.A., an international power engineering group based in Belgium, and Oro Negro, an oil services company based in Mexico. He graduated from the Université Libre de Bruxelles with a degree in engineering, and from INSEAD, Fontainebleau, France where he received an M.B.A. degree. Mr. Lambilliotte is also a trustee of the Ecofin Research Foundation, a UK-based registered charity, which aims to promote the development of sustainable, low carbon solutions.

Daniel R. Lockwood has served as a Director since May 2014. He also serves as Vice-President of New Tech Global and is responsible for overseeing and managing NTG engineering and project management services. Mr. Lockwood is a graduate of the Colorado School of Mines with a degree in Petroleum Engineering. Dan joined New Tech Engineering in 2000, and brings with him more than 35 years of engineering and management experience and is considered one of the industry’s leading experts in Shale Operations.

Dr. Christopher Rowland has been a Director of Lonestar since January 2013. He is also Director of Special Situations for Ecofin Limited where he is responsible for initiating and monitoring unlisted investments. Prior to joining Ecofin Limited in 2006, Dr. Rowland formed and led equity research teams over a 20-year period at several investment banks, including Merrill Lynch and Dresdner Klienwort Benson. Apart from his career as a research analyst, Dr. Rowland spent time setting up an alternative generator to buy coal-fired power stations in 1993. He has a Ph.D. for his research into the economics of UK oil taxation and holds a MSc (Econ) from the University of London and a BSc in Economics from the University of Bath.

Robert Scott has served as a Director since 1996. He has over 35 years experience as an advisor on corporate services and taxation, specializing in the mining and resources sector. Mr. Scott holds a Fellowship of the Australian Institute of Chartered Accountants and the Taxation Institute of Australia. Mr. Scott is currently Non-Executive Director of Homeloans Limited, Sandfire Resources Limited and RTG Mining Inc., and Non-Executive Chairman of Manas Resources Limited. Mr. Scott was formerly Chairman of bioMD Limited and Australian Renewable Fuels Limited and a Non-executive Director of New Guinea Energy Limited, Neptune Marine Services Limited and CGA Mining Limited.

John Pinkerton has served as a Director since August 2014. He has been a director of Range Resources Corporation (NYSE: RRC) since 1988 and was Chairman of its Board of Directors from 2008 until January 2015. He joined Range as President in 1990 and served as Chief Executive Officer from 1992 until 2012. Prior to joining Range, Mr. Pinkerton served in various capacities at Snyder Oil Corporation for twelve years, including the position of Senior Vice President. Mr. Pinkerton received his Bachelor of Arts degree in Business Administration from Texas Christian University, where he now serves on the board of trustees, and a Master’s degree from the University of Texas at Arlington. During his 27-year tenure Range Resources grew from its small cap origins to be a $13 billion dollar

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enterprise with a pre-eminent position in the Marcellus Shale. As CEO of Range Resources, Mr. Pinkerton established the technical expertise to enable a drilling-led strategy complemented by bolt-on acquisitions where synergies would enhance growth. This resulted in a rapid and impressive increase in the scale of the business, and seven consecutive years of double-digit growth in both production and reserves (adjusted for debt). Mr. Pinkerton has widespread skill in the management, acquisition and divestiture of oil and gas properties — including related corporate financing activities — hedging, risk analysis and the evaluation of drilling programs. He has represented the industry in policy matters, serving on the executive committee of America’s Natural Gas Alliance.

Mitchell Wells has served as a director since December 2014. Mr. Wells is an Australian qualified lawyer with legal experience in Australia, the United States and the United Kingdom. He has worked in the oil and gas sector for the past 8 years both as a Chief Operating Officer and as a Company Secretary. Mr Wells also previously served as Lonestar Resources Limited’s Company Secretary.

Codes of Business Conduct and Ethics

In connection with the Reorganization, our board of directors will adopt a code of business conduct and ethics that will apply to all of our employees, officers and directors, including our Chief Executive Officer, Chief Financial Officer and other executive officers.

Controlled Company

Ecofin Water & Power Opportunities PLC and its affiliates control a majority of the voting power of our outstanding common stock. As a result, we are a “controlled company” under Nasdaq corporate governance standards. As a controlled company, exemptions under Nasdaq standards will exempt us from certain Nasdaq corporate governance requirements, including the requirements:

· that a majority of our board of directors consists of “independent directors,” as defined under Nasdaq rules;

· that the compensation of our executive officers be determined, or recommended to the board of directors for determination, by majority vote of the independent directors or by a compensation committee comprised solely of independent directors; and

· that director nominees be selected, or recommended to the board of directors for selection, by majority vote of the independent directors or by a nomination committee comprised solely of independent directors.

Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of Nasdaq’s corporate governance requirements. In the event that we cease to be a controlled company, we will be required to comply with these provisions within the transition periods specified in Nasdaq rules.

These exemptions do not modify the independence requirements for our audit committee, and we expect to satisfy the member independence requirement for the audit committee prior to the end of the transition period provided under Nasdaq rules and SEC rules.

Board Structure

Composition

Upon completion of the Reorganization, our board of directors is expected to consist of seven members: Frank D. Bracken, III, Bernard Lambilliotte, Daniel R. Lockwood, Dr. Christopher Rowland, John Pinkerton, Mitchell Wells and Robert Scott. Each director is to hold office until his or her successor is duly elected and qualified or until his or her earlier death, resignation or removal. Vacancies and newly created directorships on the board of directors may be filled at any time by the remaining directors.

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Director Independence

Our board of directors has determined that Robert Scott is an “independent director” as such term is defined by the applicable Nasdaq rules. We may appoint new directors following the completion of the Reorganization whom we believe are independent under the applicable Nasdaq rules.

Committees of the Board

Our board of directors will have an Audit and Risk Committee, a Compensation Committee and a Nominating and Corporate Governance Committee. Under the rules of Nasdaq, the membership of the Audit and Risk Committee is required to consist entirely of independent directors, subject to applicable phase-in periods applicable to new public companies. As a controlled company, we are not required to have fully independent Compensation and Nominating and Corporate Governance Committees. The following is a brief description of our committees.

Audit and Risk Committee. Our Audit and Risk Committee will assist the board in monitoring the audit of our financial statements, our independent auditors’ qualifications and independence, the performance of our audit function and independent auditors and our compliance with legal and regulatory requirements. The Audit and Risk Committee has direct responsibility for the appointment, compensation, retention (including termination) and oversight of our independent auditors, and our independent auditors report directly to the Audit and Risk Committee. The Audit and Risk Committee will also review and approve related party transactions as required by the rules of Nasdaq.

Our Audit and Risk Committee will initially comprise Mitchell Wells, Robert Scott and Dr. Christopher Rowland. The board of directors has determined that Mr. Scott qualifies as an “audit committee financial expert.” The board has also determined that Mr. Scott is “independent” for purposes of Rule 10A-3 of the Exchange Act and Nasdaq rules, and that Mr. Wells is “independent” for purposes of Rule 10A-3 of the Exchange Act.

The board of directors has determined that Mr. Wells is not “independent” under Nasdaq listing rules as a result of his service as Company Secretary of Lonestar Resources Limited prior to the Reorganization, and that Dr. Rowland is not independent under Rule 10A-3 or Nasdaq listing rules. Accordingly, we are relying on the phase-in provisions of the Nasdaq listing rules applicable to new public companies, and we plan to have an Audit and Risk Committee comprised solely of independent directors that are independent for purposes of serving on an Audit and Risk Committee within one year of our listing. Until such time as we have independent directors available to serve on the Audit and Risk Committee, we may also rely on additional exemptions provided under Nasdaq listing rules, including the exemption afforded by Rule 5605(c)(2)(B) to the extent the board determines that reliance on such exemption would be in the best interests of the company and its shareholders.

Compensation Committee. Our Compensation Committee will review and recommend policies relating to compensation and benefits of our directors and employees and will be responsible for approving the compensation of our Chief Executive Officer and other executive officers.

Our Compensation Committee will comprise Daniel R. Lockwood, John Pinkerton, and Dr. Christopher Rowland. Our board has determined that Messrs. Lockwood, Pinkerton and Rowland are not independent under Nasdaq rules. Because we are a “controlled company” under the rules of Nasdaq, our Compensation Committee is not required to be fully independent, although if such rules change in the future or we no longer meet the definition of a controlled company under the current rules, we will adjust the composition of the Compensation Committee accordingly in order to comply with such rules.

Nominating and Corporate Governance . Our Nominating and Corporate Governance Committee will select or recommend that the board of directors select candidates for election to our board of directors, develops and recommends to the board of directors corporate governance guidelines that are applicable to us and oversees board of director and management evaluations.

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Item 6. Executive Compensation

Introduction

We are currently considered a “smaller reporting company” for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table as well as limited narrative disclosures. Further, our reporting obligations extend only to the individuals serving as our chief executive officer and our two other most highly compensated executive officers. For 2015, our named executive officers were:

· Frank D. Bracken, III, Chief Executive Officer;

· Barry D. Schneider, Chief Operating Officer; and

· Thomas H. Olle, Senior Vice President - Engineering.

Principles used to determine the nature and amount of compensation

Governance and the role of the Remuneration & Nomination Committee

Our board strives to align Lonestar’s compensation strategy with company performance and shareholder interests, and ensure that it is equitable for participants. To assist with this, prior to the Reorganization the board had in place a Remuneration & Nomination Committee, which consisted of non-executive Directors only. Lonestar’s CEO has historically attended meetings of the Remuneration & Nomination Committee but did not attend discussions regarding his compensation.

The Remuneration & Nomination Committee’s objective was to support and advise the board in fulfilling its oversight responsibility by focusing on Lonestar’s approach to executive compensation as well as the use of equity across the company.

In connection with our proposed listing on Nasdaq, we will form a Compensation Committee and adopt a charter for it in compliance with Nasdaq listing rules applicable to controlled companies. See Item 5 (“Directors and Executive Officers — Board Structure — Committees of the Board — Compensation Committee ”)

Summary of principles and the components of compensation

The structure of our executive compensation and the non-executive director compensation programs are separate and distinct. The following table is an overview of the compensation framework elements as we intend to apply to our named executive officers and our non-executive directors:

	Element	Executives	Non-Executive Directors

Fixed compensation	Base salary	ü	´

	Fees / Consultancy	´	ü

	401(k)/Australian superannuation	ü	ü

	Other benefits	ü	´

Variable compensation	Short term incentive	ü	´

	Long term incentives	ü	´

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Executive compensation policy

The objective of the executive compensation framework is to competitively and appropriately reward performance and results delivered. To this end, our compensation policy is intended to embody the following principles in its compensation framework:

· compensation should facilitate the delivery of long term results for the business and its shareholders;

· compensation should support the attraction, retention, motivation and alignment of the talent needed to achieve the organisation’s goals;

· compensation should reinforce leadership, accountability, teamwork and innovation; and

· compensation should be aligned to the contribution and performance of the business, teams and individuals.

Approach to executive compensation

Prior to the Reorganization, our Remuneration & Nomination Committee considered the appropriate level of compensation, as well as the mix and structure of fixed and variable compensation, for our executive officers. This determination will be made by our Compensation Committee following the Reorganization.

We will broadly seek to position fixed compensation in line with similar oil and gas companies. Individual positioning of compensation depends on this positioning aspiration plus consideration of experience, individual performance and Lonestar’s circumstances. When setting compensation, we seek to establish an appropriate mix between fixed and variable compensation. For fiscal 2015, most of the executives had a target package split with approximately 67% based on fixed compensation and 33% based on variable compensation.

Fixed compensation : Base salary is designed to compensate for the value the individual provides to Lonestar, including the following:

· skills and competencies needed to generate results;

· sustained contribution to the team and Lonestar; and

· the value of the role and contribution of the individual in the context of the external market.

For U.S.-based executives, retirement benefits are paid in accordance with 401(k) requirements. In line with prevalent market practice in the United States, U.S.-based executives receive health plan benefits.

Short-term incentives (“STI”): The STI plan allows for executives to receive an annual cash bonus equal to up to 50% of their base salary. The payments determined by the board take into account both Lonestar’s and the individual’s performance. Metrics used for determining the award of STI include: production and reserves growth, EBITDAX growth and achievement of EBITDAX guidance (normalized). STI awards are weighted approximately 75% for Lonestar performance and 25% individual performance. No part of the bonus is payable in future years.

Long-term incentives (“LTI”): We had two LTI plans in place during 2015 being the Lonestar Resources Limited 2012 Employee Share Option Plan (the “2012 Plan”) and the Amadeus Employee Share Option Plan. Following the Reorganization, these plans will be replaced by our Lonestar Resources US Inc. 2016 Incentive Plan (the “2016 Plan”), and options issued under the 2012 Plan will be cancelled and replaced with awards issued pursuant to the 2016 Plan.

The options that will be issued under the 2016 Plan will fall into two categories, being (i) Class A incentive options and (ii) Class B incentive options. Class A options vest equally over three years unless there is a change in control event (as defined in the 2016 Plan) or cessation of employment by

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Summary Compensation Table

The following table sets forth the compensation of our principal executive officer and the two most highly compensated executive officers other than our principal executive officer for 2015, 2014 and 2013.

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

Frank D. Bracken, III	2015	$	600,000	$	400,000	$	—	$	54,631	(3)	$	1,054,631
Chief Executive Officer	2014	$	575,000	$	300,000	$	—	$	49,043	(3)	$	924,043
	2013	$	500,000	$	250,000	$	1,674,841	$	26,000		$	2,450,841

Thomas H. Olle	2015	$	350,000	$	233,333	$	—	$	48,544	(4)	$	631,877
Senior Vice President - Operations	2014	$	337,500	$	175,000	$	—	$	47,959	(4)	$	560,459
	2013	$	300,000	$	150,000	$	960,216	$	40,500		$	1,450,716

Barry D. Schneider(5)	2015	$	420,000	$	204,467	$	—	$	59,570	(6)	$	684,037
Chief Operating Officer	2014	$	68,937	$	134,468	$	665,064	$	24,861	(6)	$	893,330
	2013	$	¾	$	¾	$	¾	$	¾		$	¾

(1) Pursuant to their respective employment agreements, each of our named executive officers is eligible for an annual cash bonus for each calendar year during his employment based upon the achievement of certain performance goals established by our board or the Remuneration & Nomination Committee, as the case may be, in its sole discretion.

(2) Represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718.

(3) For 2015, includes $30,741 paid or reimbursed to Mr. Bracken for insurance premiums incurred by him, $9,890 for executive medical coverage and $14,000 representing Mr. Bracken’s auto allowance. For 2014, includes $30,753 paid or reimbursed to Mr. Bracken for insurance premiums incurred by him, $4,290 for executive medical coverage and $14,000 representing Mr. Bracken’s auto allowance.

(4) For 2015, includes $28,344 paid of reimbursed to Mr. Olle for insurance premiums incurred by him, $9,600 representing Mr. Olle’s auto allowance and $10,600 representing company matched 401(k) contributions. For 2014, includes $27,959 paid of reimbursed to Mr. Olle for insurance premiums incurred by him, $9,600 representing Mr. Olle’s auto allowance and $10,400 representing company matched 401(k) contributions.

(5) Mr. Schneider’s employment with Lonestar commenced in May 2014.

(6) For 2015, includes $28,216 paid or reimbursed to Mr. Schneider for insurance premiums incurred by him, $8,753 for executive medical coverage, $12,000 representing Mr. Schneider’s auto allowance and $10,600 representing company matched 401(k) contributions. For 2014, includes $16,192 paid or reimbursed to Mr. Schneider for insurance premiums incurred by him, $1,019 for executive medical coverage and $7,650 representing Mr. Schneider’s auto allowance.

Outstanding Equity Awards at Fiscal Year End

The following table sets forth all outstanding equity awards held by each of our named executive officers at December 31, 2015 without giving effect to the Reorganization. As described above, in connection with the Reorganization, the options issued under the 2012 Plan will be cancelled and will be reissued pursuant to our 2016 Plan on a one for two basis.

Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Option Exercise Price (A$)		Option Expiry Date

Frank D. Bracken, III	412,058	A$	15.00	Dec. 31, 2016
Chief Executive Officer

Thomas H. Olle	236,240	A$	15.00	Dec. 31, 2016
Senior Vice President - Operations

Barry D. Schneider	150,000	A$	20.00	Dec. 31, 2017
Chief Operating Officer

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Non-executive Directors’ compensation policy

Fees and payments made to non-executive Directors for their service as Directors reflect the demands that are made on, and the responsibilities of, the Directors. Fees for non-executive Directors fees are reviewed and Lonestar seeks to position fees in line with other oil and gas companies of a similar market capitalization. Director fees are inclusive of committee fees. No termination or retirement benefits are provided to non-executive Directors. Directors may have separate consulting agreements.

Director compensation

The following table sets forth the compensation received by each non-employee Directors during our fiscal year ended December 31, 2015.

	Fees Earned or Paid in Cash ($)(1)		Option Awards ($)	All Other Compensation ($)(2)		Total ($)
Bernard Lambilliotte	$	100,000	¾	¾		$	100,000
Daniel R. Lockwood	50,000		¾	¾		50,000
Dr. Christopher Rowland	50,000		¾	$	100,000	150,000
Robert Scott	48,714		¾	¾		48,714

(1) Represents the cash portion of the annual board fees and chair fees.

(2) Other compensation for Dr. Christopher Rowland consisted of consulting fees.

Tax matters

Section 162(m) of the Internal Revenue Code of 1986 (as amended) places a limit of $1,000,000 on the amount of compensation that certain publicly held corporations may deduct for U.S. federal tax purposes in any one year with respect to certain named executives. This limitation did not apply to us for fiscal 2015 because, as of December 31, 2015, none of our shares were required to be registered under the Exchange Act.

It is expected that Section 162(m) will apply to us following the Reorganization and that our compensation committee will adopt a general practice of considering the adverse effect of Section 162(m) on the deductibility of compensation when designing annual and long-term compensation programs and approving payouts under these programs. While the tax treatment of compensation is important, the primary factor influencing program design is the support of business objectives. Consequently, it is expected that our compensation committee will reserve the right to design and administer the programs in a manner that does not satisfy the requirements of Section 162(m) and to approve the payment of non-deductible compensation if the compensation committee believes doing so may achieve a result determined to be in Lonestar’s best interest. Due to transition rules that apply to Lonestar under Section 162(m), we believe that all of the compensation that will result when our named executives exercise their currently outstanding stock options should be fully deductible.

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Item 8. Legal Proceedings.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other crude oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. We are not aware of any material pending or overtly threatened legal action against Lonestar.

Item 9. Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters.

Market Information

Lonestar Resources Limited’s ordinary shares have traded on the ASX under the trading symbol “LNR.” The shares will be delisted and will cease trading upon the completion of the Reorganization. We have applied to have our common stock listed on Nasdaq under the symbol “LONE” upon completion of the Reorganization. There can be no assurance that the listing application will be approved or that an active U.S. trading market for our common stock will develop.

The following table sets forth, for the periods indicated, the high and low closing prices of Lonestar Resources Limited’s ordinary shares on the ASX.

	High	Low
	A$	A$
*Fiscal year ending December 31, 2016*
First Quarter(1)	6.00	2.76
*Fiscal year ending December 31, 2015*
Fourth Quarter	8.70	4.95
Third Quarter	8.90	5.30
Second Quarter(1)	9.80	7.70
First Quarter(1)	13.30	8.20
*Fiscal year ended December 31, 2014*
Fourth Quarter(1)	22.00	8.00
Third Quarter(1)	29.50	17.50
Second Quarter(1)	22.50	13.00
First Quarter(1)	14.50	10.50
*Fiscal year ended December 31, 2013*
Fourth Quarter(1)	14.50	11.00
Third Quarter(1)	14.00	7.00
Second Quarter(1)	9.50	7.00
First Quarter(1)	10.50	8.00

(1) Takes into account a 50:1 share consolidation (reverse stock split) effected in May 2015 but does not give effect to the Reorganization.

As of April 30, 2016 and giving effect to the Reorganization, we had 7,521,781 shares of common stock issued and outstanding, and there were approximately 1,900 holders of record of our common stock. Upon completion of the Reorganization, which is being conducted in reliance upon the exemption from registration provided under Section 3(a)(10) of the Securities Act, our shareholders will receive one share of Lonestar Resources US Inc. common stock for every two shares of Lonestar Resources Limited shares held prior to the Reorganization.

As of the date of this registration statement and giving effect to the Reorganization, 1,114,112 shares of our common stock were subject to outstanding stock options. In connection with the Reorganization, the options issued under the 2012 Plan will be cancelled and will be reissued pursuant to our 2016 Plan on a one for two basis. We plan to file a registration statement on Form S-8 to cover the issuance of the shares of our common stock that will be issuable upon exercise of these options or options that may be issued in the future under our employee benefit plans.

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Dividends

We currently intend to retain any earnings to fund the operation and expansion of our business and do not anticipate paying any cash dividends for the foreseeable future. The declaration and payment of any dividends in the future by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. Moreover, if we determine to pay any dividend in the future, there can be no assurance that we will continue to pay such dividends . In addition, under our bank financing agreements, we are not permitted to pay cash dividends without the prior written consent of the lender.

Repurchases of Securities

Under the Delaware General Corporation Law, we are generally permitted to purchase or redeem our outstanding shares out of funds legally available for that purpose without obtaining stockholder approval, provided that (i) our capital is not impaired; (ii) such purchase or redemption would not cause our capital to become impaired; (iii) the purchase price does not exceed the price at which the shares are redeemable at our option and (iv) immediately following any such redemption, we shall have outstanding one or more shares of one or more classes or series of stock, which shares shall have full voting powers. Our certificate of incorporation does not create any further limitation on our purchase or redemption of our shares.

Item 10. Recent Sales of Unregistered Securities.

Issuances by Lonestar Resources US Inc.:

Since incorporation of Lonestar Resources US Inc. in December 2015, we have issued and sold the following securities that were not registered under the Securities Act:

In connection with the Reorganization, we will issue shares of common stock and options to purchase shares of common stock in exchange for all outstanding ordinary shares and options of Lonestar Resources Limited upon implementation of the Scheme of Arrangement. These issuances will be exempt pursuant to Section 3(a)(10) of the Securities Act.

Issuances by Lonestar Resources Limited:

Since January 1, 2012, Lonestar Resources Limited has issued and sold to third parties the securities listed below without registering the securities under the Securities Act. None of these transactions involved any public offering. All the securities were sold through private placement either (i) outside the United States or (ii) in the United States to a limited number of investors in transactions not involving any public offering. As discussed below, we believe that each issuance of these securities was exempt from, or not subject to, registration under the Securities Act. The numbers and prices of securities listed below do not take into account the 50:1 share consolidation with respect to our ordinary shares that occurred in May 2015.

1. On January 2, 2013, we issued 500,000 ordinary shares to Craig Coleman, our then Chairman, in lieu of A$50,000 of his fees as a Director. This issuance was exempt from registration under the Securities Act in reliance on Regulation S.

2. On January 2, 2013, we issued 460,000,000 ordinary shares to Ecofin Water & Power Opportunities PLC, as majority capital-holder, and minority capital-holders in Ecofin Energy Resources Plc (the previous holding company for Lonestar Resources, Inc.) in consideration for all their capital in such company. This issuance was exempt from registration under the Securities Act in reliance on Regulation S and Section 4(a)(2).

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3. On May 7, 2014, we issued 55,000,000 ordinary shares to Ecofin Water & Power Opportunities PLC, as majority capital-holder, and minority capital-holders in Ecofin Energy Resources Plc (the previous holding company for Lonestar Resources, Inc.) as deferred consideration for their capital in such company. This issuance was exempt from registration under the Securities Act in reliance on Regulation S and Section 4(a)(2).

Since January 1, 2013, Lonestar Resources Limited granted options to employees, directors and consultants under incentive compensation programs. We believe that the issuance of these securities were exempt from registration under the Securities Act in reliance upon Regulation S or Rule 701 of the Securities Act as transactions pursuant to written compensatory plans or pursuant to a written contract relating to compensation. No underwriters were employed in connection with the foregoing option grants.

Item 11. Description of Registrant’s Securities to be Registered.

The following description of our capital stock is a summary only and is qualified in its entirety by reference to our Certificate of Incorporation and Bylaws, which are included as Exhibits 3.1 and 3.2 of this registration statement.

We are authorized to issue up to 15,000,000 shares of Class A Voting Common Stock, $0.001 par value per share, and 5,000 shares of Class B Non-Voting Common Stock, $0.001 par value per share.

Holders of our Class A Voting Common Stock are entitled to one vote for each share on all matters voted on by stockholders, including the election of directors. Except as required by law, the holders of our Class B Non-Voting Common Stock will not be entitled to vote on matters voted on by stockholders.

Holders of our Class A and Class B common stock are entitled to receive dividends when and as declared by our board of directors out of funds legally available for dividends ; provided, however, that any dividend upon the common stock that is payable in common stock shall be paid only in Class A Voting Common Stock to the holders of Class A Voting Common Stock and only in Class B Non-Voting Common Stock to the holders of Class B Non-Voting Common Stock.

Holders of our common stock do not have any conversion, redemption or pre-emptive rights. In the event of any voluntary or involuntary liquidation, dissolution or winding up of the company, the holders of shares of our common stock will be entitled to receive all of the remaining assets of the company available for distribution to its stockholders, ratably in proportion to the number of shares of common stock held by them, regardless of whether such shares are Class A Voting Common Stock or Class B Non-Voting Common Stock.

Any outstanding shares of our common stock are fully paid and non-assessable.

Anti-Takeover Effects of Certain Provisions of Delaware Law and Our Certificate of Incorporation and Bylaws

Certain provisions of our Certificate of Incorporation and Bylaws may be considered as having an anti-takeover effect, such as the following provisions:

· requiring advance notice of stockholder intention to put forth director nominees or bring up other business at a stockholders’ meeting;

· requiring the affirmative vote of 66 2 / 3 % of the voting power of all then outstanding shares entitled to vote in order for stockholders to adopt, amend or repeal any provision of our Bylaws or Certificate of Incorporation; and

· providing that the number of directors shall be fixed from time to time by our board of directors pursuant to a resolution adopted by a majority of the total number of authorized

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directors (whether or not there exist any vacancies in previously authorized directorships) or by the stockholders. Newly created directorships resulting from any increase in our authorized number of directors will be filled only by a majority vote of our board of directors then in office, whether or not such directors number less than a quorum, and directors so chosen will serve for a term expiring at the annual meeting of stockholders at which the term of office to which they have been elected expires or until such director’s successor shall have been duly elected and qualified.

We are also subject to Section 203 of the Delaware General Corporation Law (the “DGCL”), which in general prohibits a Delaware corporation from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

· prior to that date, our board of directors approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;

· upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the number of shares outstanding (but not the outstanding voting stock owned by the interested stockholder) those shares owned by (i) persons who are directors and also officers and (ii) employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or

· on or subsequent to that date, the business combination is approved by our board of directors and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2 / 3 % of the outstanding voting stock that is not owned by the interested stockholder.

In general, Section 203 defines an interested stockholder as an entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by any of these entities or persons.

The above-summarized provisions of the DGCL and our Certificate of Incorporation and Bylaws could make it more difficult to acquire us by means of a tender offer, a proxy contest or otherwise, or to remove incumbent officers and directors. These provisions are expected to discourage certain types of coercive takeover practices and takeover bids that our board of directors may consider inadequate and to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging takeover or acquisition proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Listing

We have applied to list our common stock on Nasdaq under the symbol of “LONE.”

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is Computershare.

Item 12. Indemnification of Directors and Officers.

Our Certificate of Incorporation provides that, our directors shall not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except to the

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Item 15. Financial Statements and Exhibits.

(a) Financial Statements

Our consolidated financial statements appear on pages F-1 through F-46 of this registration statement.

(b) Exhibits

Exhibit Number		Description

2.1*		Scheme Implementation Agreement, by and between Lonestar Resources US Inc. and Lonestar Resources Limited, executed on December 28, 2015

3.1*		Certificate of Incorporation of Lonestar Resources US Inc.

3.2*		Bylaws of Lonestar Resources US Inc.

4.1*		Indenture, dated April 4, 2014 among Lonestar Resources America Inc., its subsidiary guarantors and Wells Fargo Bank, National Association, as trustee

10.1*		Form of Indemnification Agreement for Directors and executive officers

10.2*		Credit Agreement, dated July 28, 2015, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto (previously filed as Exhibit 10.3)

10.3*		Joint Development Agreement, dated July 27, 2015, between Lonestar Resources America Inc. and IOG South Texas I, LLC

10.4*		Lonestar Resources US Inc. 2016 Incentive Plan

10.5		First Amendment to Credit Agreement, dated effective April 29, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.

10.6		Second Amendment to Credit Agreement, dated effective May 19, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto.

21.1*		List of significant subsidiaries of Lonestar Resources US Inc.

23.1*		Consent of BDO USA, LLP

23.2*		Consent of W.D. Von Gonten & Co.

23.3*		Consent of LaRoche Petroleum Consultants, Ltd.

99.1*		Report of W.D. Von Gonten & Co. regarding the registrant’s estimated proved reserves as of December 31, 2013, dated March 22, 2014

99.2*		Report of W.D. Von Gonten & Co. regarding the registrant’s estimated proved reserves as of December 31, 2014, dated January 29, 2015

99.3*		Report of W.D. Von Gonten & Co. regarding the registrant’s estimated proved reserves as of December 31, 2015, dated February 22, 2016.

99.4*		Report of LaRoche Petroleum Consultants, Ltd. regarding the registrant’s estimated proved reserves as of December 31, 2013, dated January 28, 2014 (previously filed as Exhibit 99.3)

99.5*		Report of LaRoche Petroleum Consultants, Ltd. regarding the registrant’s estimated proved reserves as of December 31, 2014, dated January 30, 2015 (previously filed as Exhibit 99.4)

99.6*		Report of LaRoche Petroleum Consultants, Ltd. regarding the registrant’s estimated proved reserves as of December 31, 2015, dated January 15, 2016.

* Previously filed.

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Lonestar Resources Limited

Consolidated Balance Sheets

	March 31, 2016 (unaudited)		December 31, 2015

Assets

Current assets
Cash and cash equivalents	$	4,188,153	$	4,321,456
Accounts receivable:
Oil, natural gas liquid and natural gas sales	4,515,568		5,043,398
Joint interest owners and other	1,424,408		1,305,146
Related parties	—		279,043
Derivative financial instruments	25,168,192		33,218,474
Prepaid expenses and other	889,554		723,988

Total current assets	36,185,875		44,891,505

Oil and gas properties, net, using the successful efforts method of accounting	489,752,167		488,099,597
Other property and equipment (net of accumulated depreciation of $1,217,175 and $1,067,956, respectively)	2,250,737		2,223,399
Derivative financial instruments	1,994,328		2,864,372
Other noncurrent assets	1,601,337		1,580,160
Restricted certificates of deposit	77,444		77,397

Total assets	$	531,861,888	$	539,736,430

See accompanying notes to unaudited consolidated financial statements.

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Lonestar Resources Limited

Consolidated Balance Sheets (continued)

	March 31, 2016 (unaudited)			December 31, 2015

Liabilities and Stockholders’ Equity

Current liabilities
Accounts payable	$	20,501,431		$	18,027,156
Accounts payable — related parties	195,993			44,848
Oil, natural gas liquid and natural gas sales payable	3,137,141			3,870,464
Accrued liabilities	16,259,133			8,276,085
Accrued liabilities — related parties	37,500			125,000

Total current liabilities	40,131,198			30,343,553

Long-term debt	301,262,517			301,926,051
Deferred tax liability	10,144,910			16,013,276
Other non-current liabilities	1,000,000			1,000,000
Asset retirement obligations	7,557,671			7,487,501

Total liabilities	360,096,296			356,770,381

Commitments and contingencies

Stockholders’ equity
Common stock, $0.20 par value, 500,000,000 shares authorized, 15,044,051 shares issued and outstanding at March 31, 2016 and December 31, 2015	142,637,636			142,637,636
Additional paid-in capital	10,365,614			10,270,288
Accumulated other comprehensive loss	(758,950		)	(760,366		)
Retained earnings	19,521,292			30,818,491

Total stockholders’ equity	171,765,592			182,966,049

Total liabilities and stockholders’ equity	$	531,861,888		$	539,736,430

See accompanying notes to unaudited consolidated financial statements.

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Lonestar Resources Limited

Unaudited Consolidated Statements of Operations and Other Comprehensive Income (Loss)

Three months ended March 31,	2016			2015

Revenues
Oil sales	$	8,951,438		$	16,221,327
Natural gas sales	1,621,606			1,327,266
Natural gas liquid sales	623,610			513,248

Total revenues	11,196,654			18,061,841

Operating expenses
Lease operating	4,673,155			3,461,048
Production, ad valorem, and severance taxes	915,445			1,350,960
Depletion, depreciation, and amortization	15,138,729			12,785,384
Accretion of asset retirement obligations	56,401			52,363
Stock-based compensation	95,326			432,837
General and administrative	2,772,986			2,288,795

Total operating expenses	23,652,042			20,371,387

Loss from operations	(12,455,388		)	(2,309,546		)

Other income (expense)
Interest expense	(6,124,452		)	(5,846,680		)
Gains on derivative financial instruments	1,715,801			6,974,757
Other expense	(228,070		)	(663,924		)

Total other income (expense), net	(4,636,721		)	464,153

Loss before income taxes	(17,092,109		)	(1,845,393		)

Income tax benefit	5,794,910			1,120,044

Net loss	$	(11,297,199	)	$	(725,349	)

Net income (loss) per common share-basic and diluted	$	(0.75	)	$	(0.05	)
Weighted average common shares outstanding—basic and diluted	15,044,051			15,044,051

Net loss	$	(11,297,199	)	$	(725,349	)

Other comprehensive income
Foreign currency translation adjustments	1,416			13,676

Comprehensive loss	$	(11,295,783	)	$	(711,673	)

See accompanying notes to unaudited consolidated financial statements.

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Lonestar Resources Limited

Unaudited Consolidated Statements of Changes in Stockholders’ Equity

	Common Stock			Additional Paid-in		Retained			Accumulated other comprehensive			Total Stockholder’s
	Shares	Amount		Capital		Earnings			loss			Equity

Balance at December 31, 2015	15,044,051	$	142,637,636	$	10,270,288	$	30,818,491		$	(760,366	)	182,966,049

Stock-based compensation	—	—		95,326		—			—			95,326

Foreign currency translation	—	—		—		—			1,416			1,416

Net loss	—	—		—		(11,297,199		)	—			(11,279,199	)

Balance at March 31, 2016	15,044,051	$	142,637,636	$	10,365,614	$	19,521,292		$	(758,950	)	171,765,592

See accompanying notes to unaudited consolidated financial statements.

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Lonestar Resources Limited

Unaudited Consolidated Statements of Cash Flows

Three months ended March 31,	2016			2015

Operating activities
Net loss	$	(11,297,199	)	$	(725,349	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss on sale of oil and gas properties	—			629,253
Accretion of asset retirement obligations	56,400			52,363
Depreciation, depletion, and amortization	15,138,729			12,785,384
Stock-based compensation	95,326			432,837
Deferred taxes	(5,868,366		)	(1,120,683		)
Gain on derivative financial instruments	(1,715,801		)	(6,974,757		)
Settlements of derivative financial instruments	10,636,127			9,564,137
Impairment of oil and gas properties	22,836			—
Non-cash interest expense	275,000			275,000
Changes in operating assets and liabilities:
Accounts receivable	687,611			6,561,205
Prepaid expenses and other assets	(103,923		)	(402,170		)
Accounts payable and accrued expenses	9,787,648			(13,269,584		)

Net cash provided by operating activities	17,714,388			7,807,636

Investing activities
Acquisition of oil and gas properties	(2,064,611		)	(3,141,568		)
Development of oil and gas properties	(14,586,535		)	(23,003,404		)
Purchases of other property and equipment	(176,558		)	(45,040		)

Net cash used in investing activities	(16,827,704		)	(26,190,012		)

Financing activities
Proceeds from bank borrowings	7,000,000			12,000,000
Payments on bank borrowings	(8,000,000		)	—
Payments on other note payable	(21,403		)	(27,508		)

Net cash provided by (used in) financing activities	(1,021,403		)	11,972,492

Effect of exchange rate changes on cash and cash equivalents	1,416			13,676

Decrease in cash and cash equivalents	(133,303		)	(6,396,208		)
Cash and cash equivalents, beginning of the year	4,321,456			9,992,477

Cash and cash equivalents, end of the period	$	4,188,153		$	3,596,269

Supplemental information
Cash paid for interest expense	$	704,641		$	484,000

See accompanying notes to unaudited consolidated financial statements.

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Lonestar Resources Limited

Notes to Unaudited Consolidated Financial Statements

1. Nature of Business and Presentation

Lonestar Resources Limited (the “Parent”) is a company limited by shares incorporated in Australia, whose shares are publicly traded on the Australian Securities Exchange and the OTCQX. The financial report consists of consolidated financial statements for Lonestar Resources Limited and its subsidiaries.

Lonestar Resources America, Inc., as combined with Parent (the “Company”) is a Delaware registered U.S. holding company formed January 31, 2013, which is engaged in the exploration, development, production, acquisition, and sale of oil, natural gas liquid (“NGL”) and natural gas primarily in the Eagle Ford Shale Play in South Texas, Conventional properties in North Texas and Bakken properties in Montana through its wholly owned subsidiaries. Its executive offices are located in Fort Worth, Texas. The Company is a wholly owned subsidiary of the Parent. The majority of the activities of the Parent is carried out through Lonestar Resources America, Inc.

Lonestar Resources America, Inc. was formed as a U.S. holding company for Lonestar Resources, Inc. and Amadeus Petroleum, Inc., which are subsidiaries previously wholly-owned by the Parent. This formation was effected through an exchange of shares of the Company for those issued by the merged subsidiaries and has been treated as a reorganization of entities under common control.

Basis of Presentation

The accompanying interim consolidated financial statements have not been audited by independent public accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim related disclosures in these consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules of the Securities and Exchange Commission. The results of operations and the cash flows for the three months ended March 31, 2016 are not necessarily indicative of the results to be expected for the full year.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company’s wholly owned subsidiaries:

Lonestar Reources America, Inc. (“LRAI”),

Lonestar Resources, Inc. (“LRI”),

Barnett Gas, LLC (“Barnett Gas”),

Eagleford Gas, LLC (“Eagleford Gas”),

Poplar Energy, LLC (“Poplar”),

Eagleford Gas 2, LLC (“Eagleford Gas 2”),

Eagleford Gas 3, LLC (“Eagleford Gas 3”),

Eagleford Gas 4, LLC (“Eagleford Gas 4”),

Eagleford Gas 5, LLC (“Eagleford Gas 5”),

Eagleford Gas 6, LLC (“Eagleford Gas 6”),

Eagleford Gas 7, LLC (“Eagleford Gas 7”),

Eagleford Gas 8, LLC (“Eagleford Gas 8”),

Lonestar Operating, LLC (“LNO”),

Amadeus Petroleum, Inc. (“API”),

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Lonestar Resources Limited

Notes to Unaudited Consolidated Financial Statements

T-N-T Engineering, Inc. (“TNT”) and

Albany Services, LLC (“Albany”).

All significant intercompany balances and transactions have been eliminated in consolidation.

2. Recently Issued Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. This ASU is effective for the annual period ending after December 15, 2018, and for annual interim periods thereafter. Early adoption is permitted. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements.

In November 2015, the FASB issued ASU No. 2015-17 to simplify income tax accounting. The update requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. This update is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and may be adopted earlier on a voluntary basis. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements — Going Concern” (Subtopic 205-40). This ASU provides guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. Management does not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but only for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method of adoption. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and the method of adoption.

In March 2016, the FASB issued updated guidance as part of its simplification initiative which is intended to simplify several aspects of the accounting for stock-based compensation transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. Management is currently evaluating what the effects of adopting this updated guidance will be on its consolidated financial statements.

In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability, other than those costs related to line of credit arrangements, be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, similar to the presentation for debt discounts and premiums, instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. This guidance was effective for the Company on January 1, 2016. The Company’s adoption of this guidance was applied retrospectively and did not have a material impact on the Company’s consolidated financial statements.

3. Acquisitions and Divestitures

During January to March 2016 the Company paid approximately $770,000 to acquire approximately 220 net acres in La Salle County surrounding Company developed areas and new undeveloped areas. During January to March 2016 the Company paid approximately $1,100,000 to acquire approximately 814 net acres in Gonzales County for new well development.

In January 2015 the Company exchanged its working interest in two non-operated wells and the underlying leasehold acreage for increased working interests in currently owned and operated

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Lonestar Resources Limited

Notes to Unaudited Consolidated Financial Statements

property. The exchange resulted in a loss of $629,000. Additionally, the Company acquired 159 net acres in the Eagle Ford Shale trend in La Salle County for $500,000 as a further component of the exchange.

4. Restricted Certificates of Deposit

The Company is required to maintain certain certificates of deposit (“CDs”) by a municipality in which drilling operations are located. This CD is pledged as collateral for a letter of credit issued by the Company’s bank to the municipality. The CD has a maturity date of March 8, 2017, and bears an interest rate of 0.25%. As this CD is expected to be renewed upon maturity and is not available for use in operations, it is classified as a noncurrent asset.

5. Commodity Price Risk Activities

The Company has implemented a strategy to reduce the effects of volatility of oil and natural gas prices on the Company’s results of operations by securing fixed price contracts for a portion of its expected sales volumes.

Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not currently require collateral from any of its counterparties nor does its counterparties require collateral from the Company. At March 31, 2016, the Company had no open physical delivery obligations.

The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future oil, NGL and natural gas production and related cash flows. The oil, NGL and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future oil, NGL and natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget. The Company has not designated any of the commodity derivatives as hedges under the applicable accounting standards. Consequently, all changes in fair value of these derivative (realized and unrealized) are included in the consolidated statement of operations.

As of March 31, 2016, the following derivative transactions were outstanding:

Instrument	Total Volume	Settlement Period	Fixed Price

Oil - WTI Fixed Price Swap	151,000 BBL	April - December 2016	84.45
Oil - WTI Fixed Price Swap	224,100 BBL	April - December 2016	90.45
Oil - WTI Fixed Price Swap	94,700 BBL	April - December 2016	63.20
Oil - WTI Fixed Price Swap	125,900 BBL	April - December 2016	56.90

Instrument	Total Volume	Settlement Period	Puts		Calls

Oil - 3 Way Collar	365,100 BBL	January - December 2017	$	40.00 / 60.00	$	85.00

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Lonestar Resources Limited

Notes to Unaudited Consolidated Financial Statements

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015, for each fair value hierarchy level:

	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
March 31, 2016
Assets:
Commodity derivatives	$	—	$	27,162,520	$	—	$	27,162,520
Liabilities:
Commodity derivatives	—		—		—		—

Total	$	—	$	27,162,520	$	—	$	27,162,520

December 31, 2015
Assets:
Commodity derivatives	$	—	$	36,082,846	$	—	$	36,082,846
Liabilities:
Commodity derivatives	—		—		—		—

Total	$	—	$	36,082,846	$	—	$	36,082,846

The book values of cash and cash equivalents, receivables for oil, NGL and natural gas sales, joint interest billings, notes and other receivables, accounts payable, and accrued liabilities approximate fair value due to the short-term nature of these instruments. The carrying value of debt approximates fair value since it is subject to a short-term floating interest rate that approximates the rate available to the Company.

7. Oil and Gas Properties

A summary of oil and gas properties follows:

	March 31, 2016 (unaudited)			December 31,2015

Proved properties and equipment	$	599,102,114		$	584,691,945
Unproved properties	72,530,259			70,298,349
Less accumulated depreciation, depletion, and amortization	(181,880,206		)	(166,890,697		)

	$	489,752,167		$	488,099,597

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Lonestar Resources Limited

Notes to Unaudited Consolidated Financial Statements

8. Accrued Liabilities

The accrued liabilities consist of the following:

	March 31, 2016 (unaudited)		December 31,2015

Bonus payable	$	1,642,915	$	1,432,768
Severance and vacation payable	23,315		28,388
Accrued interest	9,301,280		4,420,317
Accrued rent	383,172		409,643
Accrued expenses	4,543,187		1,401,080
Other	365,264		583,889

	$	16,259,133	$	8,276,085

9. Long-Term Debt

The Company’s debt consists of the following:

December 31,	March 31, 2016 (unaudited)			December 31, 2015

Revolving credit facility	$	86,000,000		$	87,000,000
8.75% senior notes	220,000,000			220,000,000
Less discount on 8.75% senior notes	(3,300,000		)	(3,575,000		)
Less deferred financing costs on 8.75% senior notes	(1,701,592		)	(1,784,461		)
Other	264,109			285,512

	$	301,262,517		$	301,926,051

Senior Revolving Credit Facility

On July 28, 2015, the Company closed a new $500,000,000 Senior Secured Credit Facility which replaced the $400,000,000 Wells Fargo led syndicated facility outlined below. The new facility was arranged by Citibank, N.A. and features an expanded borrowing base of $180,000,000 as of December 31, 2015. The new facility provides additional liquidity for the Company and a lower interest rate. The new rate is a 25 basis point improvement over the LIBOR interest rate spread. The new facility provides for an extension in the maturity date to October 16, 2018, which represents a seven month extension over the Wells Fargo led facility. The financial covenants contained in this new facility are substantially the same as the previous facility. As of March 31, 2016 and December 31, 2015, the Company was in compliance with all covenants including all financial ratios under the Citibank led facility. As of March 31, 2016 and December 31, 2015, $86,000,000 and $87,000,000 was borrowed, respectively, under the Citibank led revolving credit facility. Effective May 19, 2016, the Company received notification that the borrowing base was reduced to $120,000,000. Also, redeterminations are now scheduled semi-annually to occur on May 1 and November 1 of each year. The next borrowing base redetermination is scheduled for November 1, 2016.

The revolving credit facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. The revolving credit facility provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the revolving credit facility.

Borrowings under the revolving credit facility, at the Company’s election, bear interest at either: (i) an alternate base rate (“ABR”) equal to the higher of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% per annum, and (c) the adjusted LIBO rate of a three-month interest period on such day plus 1.0%; or (ii) the adjusted LIBO rate, which is the rate stated on Reuters screen LIBOR01 page, for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii)

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Lonestar Resources Limited

Notes to Unaudited Consolidated Financial Statements

above, an applicable margin ranging from 0.75% to 1.75% for ABR loans and from 1.75% to 2.75% for adjusted LIBO rate loans.

The revolving credit facility requires the Company to maintain certain financial ratios and limits the amount of indebtedness the Company can incur. Subject to certain permitted liens, the Company’s obligations under the revolving credit facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its subsidiaries.

In connection with the revolving credit facility, the Company and certain of its subsidiaries also entered into certain customary ancillary agreements and arrangement, which, among other things, provide that the indebtedness, obligations, and liabilities of the Company arising under or in connection with the revolving credit facility are unconditionally guaranteed by such subsidiaries.

In March 2013, the Company entered into a $400,000,000 syndicated credit facility agreement (“revolving credit facility”) with Wells Fargo Bank (as Administrative Agent). The initial borrowing base was set at $105,000,000. The borrowing base was determined semi-annually based on the credit agreement, and such re-determined borrowing base became effective and applicable on April 1 and October 1 of each year commencing October 1, 2013. The revolving credit facility matured on March 14, 2018. This revolving credit facility was replaced on July 28, 2015, as outlined above.

8.75% Senior Notes

On April 4, 2014, the Company issued at par $220,000,000 of 8.75% Senior Unsecured Notes due April 15, 2019 (“Notes”) to U.S. based institutional investors. The net proceeds from the offering of approximately $212,000,000 (after deducting purchasers’ discounts and offering expenses) were used to repay the Company’s revolving credit facility and 2nd lien facility, and for general corporate purposes. Under the 2nd lien term loan agreement, the Company was required to pay a prepayment fee of $1,100,000 in connection with the early prepayment of the facility equal to 2.0% of the principal balance that was prepaid. This facility was terminated upon repayment.

On or after April 15, 2016, the Company may redeem the Notes in whole or in part at the redemption prices (expressed as percentages of the principal amount) set forth in the following table plus accrued and unpaid interest, if any, on the Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

Year	Percentage
2016	106.563	%
2017	104.375	%
2018 and thereafter	100.000	%

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Lonestar Resources Limited

Notes to Unaudited Consolidated Financial Statements

Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of Parent’s common shares at the beginning of the quarter in which the stock option is granted. The volatility of 58.6% is based on weighted average historical movements of Parent’s common share price on the ASX over a period that approximates the expected life.

Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life.

Expected Dividend Yield. Parent has not paid any cash dividends on its common shares and does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model.

Expected Forfeitures . The Company has experienced limited forfeitures and therefore has not discounted expenses for forfeitures at the reporting date.

Stock Option Activity

For the three months ended March 31, 2016, no stock options were exercised. The following tables summarize certain information related to outstanding stock options under the 2012 Plan:

	Shares	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term (in years)

Outstanding at December 31, 2015	1,699,872	15.50		1.0
Options vested and exercisable at December 31, 2015	1,615,372	$	15.50	1.0
Granted	—	—		—
Exercised	—	—		—
Canceled/Expired	—	—		—
Forfeited	—	—		—
Outstanding at March 31, 2016	1,699,872	15.50		1.0
Options vested and exercisable at March 31, 2016	1,615,372	$	15.50	1.0

	Shares	Weighted Average Fair Value per Share		Weighted Average Exercise Price per share		Weighted Average Remaining Contractual Term (in years)

Outstanding non-vested options at December 31, 2015	84,500	$	4.50	$	15.50	1.0

Granted	—	—		—		—
Vested	—	—		—		—
Forfeited	—	—		—		—
Outstanding non-vested options at March 31, 2016	84,500	$	4.50	$	15.50	1.0

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Lonestar Resources Limited

Notes to Unaudited Consolidated Financial Statements

Stock-Based Compensation Expense

For the three month period ended March 31, 2016, the Company recorded stock-based compensation expense for stock options granted using the fair-value method of $95,326.

11. Earnings Per Share

In accordance with the provisions of current authoritative guidance, basic earnings or loss per share shown on the Consolidated Statements of Operations is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities.

In connection with a planned reorganization, a new corporate entity was formed, Lonestar Resources US Inc., which immediately prior to the reorganization will acquire the Parent via an Australian Scheme of Arrangement. As a result, certain accounting policies have been adopted in these financial statements as if the Company were a public company. The following table presents unaudited pro forma earnings per share of Lonestar Resources US Inc., assuming that the 1 for 2 reverse stock split upon reorganization had occurred at the beginning of three month periods ended March 31, 2016 and 2015:

Unaudited Pro Forma Earnings Per Share (After Reorganization)

	March 31, 2016			March 31, 2015

Net income (loss) per common share:
Basic	$	(1.50	)	$	(0.10	)
Diluted	(1.50		)	(0.10		)

Weighted average common shares outstanding:
Basic	7,522,025			7,522,025
Diluted	7,522,025			7,522,025

12. Related Party Activities

In April 2014, the Company loaned $539,000 in total to Frank D. Bracken, III and Thomas H. Olle to assist with their tax obligations as a result of stock compensation awarded to them in 2013. The loans were on arms-length commercial terms and were settled in full in January 2016.

Butterfly Flaps, Ltd, a company in which Dr. Christopher Rowland (a director of Parent) owns an interest, has performed consultancy work for Lonestar since 2013 covering various strategic, tax structuring and investor matters at a cost of approximately $25,000 per quarter.

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Lonestar Resources Limited

Consolidated Balance Sheets

December 31,	2015		2014

Assets

Current assets
Cash and cash equivalents	$	4,321,456	$	9,992,477
Accounts receivable:
Oil, natural gas liquid and natural gas sales	5,043,398		8,987,525
Joint interest owners and other	1,305,146		7,933,752
Related parties	279,043		562,634
Derivative financial instruments	33,218,474		31,045,260
Prepaid expenses and other	723,988		654,880

Total current assets	44,891,505		59,176,528

Oil and gas properties, net, using the successful efforts method of accounting	488,099,597		481,079,275
Other property and equipment (net of accumulated depreciation of $1,067,956 and $680,002, respectively)	2,223,399		2,366,013
Derivative financial instruments	2,864,372		12,713,295
Other noncurrent assets	3,364,621		3,608,331
Restricted certificates of deposit	77,397		125,980

Total assets	$	541,520,891	$	559,069,422

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Lonestar Resources Limited

Consolidated Balance Sheets (continued)

December 31,	2015			2014

Liabilities and Stockholders’ Equity

Current liabilities
Accounts payable	$	18,027,156		$	30,650,081
Accounts payable – related parties	44,848			192,187
Oil, natural gas liquid and natural gas sales payable	3,870,464			4,961,510
Accrued liabilities	8,276,085			11,605,120
Accrued liabilities – related parties	125,000			—

Total current liabilities	30,343,553			47,408,898

Long-term debt	303,710,512			264,613,529
Deferred tax liability	16,013,276			31,510,744
Other non-current liabilities	1,000,000			1,000,000
Asset retirement obligations	7,487,501			6,834,615

Total liabilities	358,554,842			351,367,786

Commitments and contingencies (Note 13)

Stockholders’ equity
Common stock, $.20 par value, 500,000,000 shares authorized, 15,044,051 and 14,661,004 shares issued and outstanding at December 31, 2015 and 2014, respectively	142,637,636			142,637,636
Additional paid-in capital	10,270,288			7,685,177
Accumulated other comprehensive loss	(760,366		)	(772,633		)
Retained earnings	30,818,491			58,151,456

Total stockholders’ equity	182,966,049			207,701,636

Total liabilities and stockholders’ equity	$	541,520,891		$	559,069,422

See accompanying notes to consolidated financial statements.

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Lonestar Resources Limited

Consolidated Statements of Operations and Other Comprehensive Income (Loss)

Years ended December 31,	2015				2014

Revenues
Oil sales	$		70,739,269		$	104,233,379
Natural gas sales	6,823,019				7,589,599
Natural gas liquid sales	1,928,068				3,803,582

Total revenues	79,490,356				115,626,560

Operating expenses
Lease operating and gas gathering	17,853,428				16,631,611
Production, ad valorem, and severance taxes	4,981,826				7,123,332
Depletion, depreciation, and amortization	58,827,705				40,521,546
Accretion of asset retirement obligations	214,335				201,076
Impairment of oil and gas properties	28,622,961				5,478,264
Stock-based compensation	2,585,111				1,938,400
General and administrative	10,824,845				8,913,052

Total operating expenses	123,910,211				80,807,281

Income (loss) from operations	(44,419,855			)	34,819,279

Other income (expense)
Interest expense	(24,576,993			)	(19,949,359		)
Gains on derivative financial instruments	27,608,534				43,972,245
Other income (expense)	(1,065,539			)	55,187

Total other income, net	1,966,002				24,078,073

Income (loss) before taxes	(42,453,853			)	58,897,352

Income tax (expense) benefit	15,120,888				(22,431,722		)

Net income (loss)	$		(27,332,965	)	$	36,465,630

Net income (loss) per common share-basic	$		(1.82	)	$	2.49
Net income (loss) per common share-diluted	$		(1.82	)	$	2.42
Weighted average common shares outstanding–basic	15,044,051				14,661,004
Weighted average common shares outstanding–diluted	15,044,051				15,069,610

Other comprehensive income (loss):
Net income (loss)	$	(27,332,965		)	$	36,465,630
Foreign currency translation adjustments	12,267				(404,038		)
Comprehensive income (loss)	$	(27,320,698		)	$	36,061,592

See accompanying notes to consolidated financial statements.

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Lonestar Resources Limited

Consolidated Statements of Changes in Stockholders’ Equity

						Accumulated
						Other					Total
	Common Stock			Additional		Comprehensive		Retained			Stockholders,
	Shares	Amount		Paid-in Capital		Income (Loss)		Earnings			Equity
Balance at December 31, 2013	13,943,744	$	142,637,636	$	5,746,777	(368,595	)	$	21,685,826		169,701,644
Share issuance	1,100,000	—		—		—		—			—
Stock-based compensation	—	—		1,938,400		—		—			1,938,400
Foreign currency translation	—	—				(404,038	)	—			(404,038		)
Net income	—	—		—		—		36,465,630			36,465,630
Balance at December 31, 2014	15,043,744	$	142,637,636	$	7,685,177	(772,633	)	$	58,151,456		$	207,701,636
Share issuance	307	—		—		—		—			—
Stock-based compensation	—	—		2,585,111		—		—			2,585,111
Foreign currency translation	—	—				12,267		—			12,267
Net loss	—	—		—		—		(27,332,965		)	(27,332,965		)
Balance at December 31, 2015	15,044,051	$	142,637,636	$	10,270,288	(760,366	)	$	30,818,491		$	182,966,049

See accompanying notes to consolidated financial statements.

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Consolidated Statements of Cash Flows

Years ended December 31,	2015			2014

Operating activities
Net income (loss)	$	(27,332,965	)	$	36,465,630
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
(Gain) loss on sale of oil and gas properties	629,253			(466,490		)
Accretion of asset retirement obligations	214,335			201,076
Depreciation, depletion, and amortization	58,827,705			40,521,546
Stock-based compensation	2,585,111			1,938,400
Deferred taxes	(15,497,468		)	22,662,988
Gain on derivative financial instruments	(27,608,534		)	(43,972,245		)
Settlements of derivative financial instruments	35,284,243			(1,503,609		)
Impairment of oil and gas properties	28,622,961			5,478,264
Non-cash interest expense	1,100,000			825,000
Changes in operating assets and liabilities:
Accounts receivable	10,856,325			(9,408,033		)
Prepaid expenses and other assets	223,186			(1,856,749		)
Accounts payable and accrued expenses	(17,065,347		)	31,341,672

Net cash provided by operating activities	50,838,805			82,227,450

Investing activities
Acquisition of oil and gas properties	(8,723,497		)	(70,978,282		)
Development of oil and gas properties	(85,458,433		)	(164,180,576		)
Purchases of other property and equipment	(337,147		)	(1,086,073		)
Proceeds from sales of oil and gas properties	—			3,200,000

Net cash used in investing activities	(94,519,077		)	(233,044,931		)

Financing activities
Proceeds from bank borrowings	140,513,602			135,000,000
Payments on bank borrowings	(102,513,602		)	(195,000,000		)
Proceeds from bond offering	—			214,500,000
Payment on other note payable	(3,016		)	(30,000		)

Net cash provided by financing activities	37,996,984			154,470,000

Effect of exchange rate changes on cash and cash equivalents	12,267			(404,038		)
Increase (decrease) in cash and cash equivalents	(5,671,021		)	3,248,481
Cash and cash equivalents, beginning of the year	9,992,477			6,743,996

Cash and cash equivalents, end of the year	$	4,321,456		$	9,992,477

Supplemental information
Cash paid for federal income taxes	$	257,000		$	90,000
Cash paid for interest expense	$	21,492,189		$	13,400,795

See accompanying notes to consolidated financial statements.

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Lonestar Resources Limited

Notes to Consolidated Financial Statements

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company’s wholly owned subsidiaries:

Lonestar Resources America, Inc. (“LRAI”),

Lonestar Resources, Inc. (“LRI”),

Barnett Gas, LLC (“Barnett Gas”),

Eagleford Gas, LLC (“Eagleford Gas”),

Poplar Energy, LLC (“Poplar”),

Eagleford Gas 2, LLC (“Eagleford Gas 2”),

Eagleford Gas 3, LLC (“Eagleford Gas 3”),

Eagleford Gas 4, LLC (“Eagleford Gas 4”),

Eagleford Gas 5, LLC (“Eagleford Gas 5”),

Eagleford Gas 6, LLC (“Eagleford Gas 6”),

Eagleford Gas 7, LLC (“Eagleford Gas 7”),

Eagleford Gas 8, LLC (“Eagleford Gas 8”),

Lonestar Operating, LLC (“LNO”),

Amadeus Petroleum, Inc. (“API”),

T-N-T Engineering, Inc. (“TNT”) and

Albany Services, LLC (“Albany”).

All significant intercompany balances and transactions have been eliminated in consolidation.

Reclassifications

Certain prior year amounts which were determined to be immaterial have been reclassified to conform to current year presentation, with no effect on the previously reported results of operations.

Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less when purchased to be cash equivalents.

Currency Translation

The consolidated financial statements are presented in U.S. dollars. The functional currency of Parent is the Australian Dollar. At the end of each reporting period, the assets and liabilities of Parent are translated from its functional currency to U.S. dollars using the exchange rate at the end of the month. The monthly results of operations of Parent are generally translated from its functional currency to U.S. dollars using the average exchange rate during the month. Changes in exchange rates result in currency translation gains and losses, which are recorded within other comprehensive income (loss).

Parent may also enter into transactions in currencies other than their functional currency. At the end of each reporting period, Parent re-measures the related receivables, payables, and cash to its functional currency using the exchange rate at the end of the period. Changes in exchange rates between the time the transactions were entered into and the end of the reporting period result in currency transaction gains or losses, which are recorded in the consolidated statements of operations.

Concentrations and Credit Risk

The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. The Company places its cash and cash equivalents with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not incurred any losses related to amounts in excess of FDIC limits.

Substantially all of the Company’s accounts receivable are due from either purchasers of oil, NGL and natural gas or working interest partners in oil and natural gas wells for which a subsidiary of the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company’s receivables are generally unsecured. The Company has experienced no credit losses since its inception and does not carry an allowance for uncollectible amounts at December 31, 2015.

Oil, NGL and natural gas revenues from Trafigura AG, BP Products North America LLC, Shell Trading (US) Company and Texla Energy Management, Inc. for the year ended December 31, 2015, represented 38%, 20%, 16% and 11%, respectively, of total revenues. Oil, NGL and natural gas revenues from Shell Trading (US) Company, Trafigura AG and BP Products North America LLC for the year ended December 31, 2014, represented 36%, 23% and 16%, respectively, of total revenues. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and Texla Energy Management, Inc. represented 26%, 25% and 23%, respectively, of total receivables at December 31, 2015. Accounts receivable relating to oil, NGL and natural gas

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Notes to Consolidated Financial Statements

sales from Shell Trading, Trafigura AG and BP Products North America LLC represented 19%, 27% and 32%, respectively, of total receivables at December 31, 2014.

Prepaid Expenses

Prepaid expenses generally relate to prepaid drilling and completion costs that will be capitalized into oil and gas properties.

Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting to account for its oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The Company’s policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive.

Other Property and Equipment

Other property and equipment, consisting primarily of office, transportation and computer equipment, is carried at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years. Major renewals and improvements are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Upon

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Notes to Consolidated Financial Statements

Fair Value of Financial Instruments

In accordance with the reporting requirements of ASC 825, Financial Instruments , the Company calculates the fair value of its assets and liabilities that qualify as financial instruments under this guidance and includes this additional information in the notes to consolidated financial statements when the fair value is different from the carrying value of those financial instruments. See Note 6.

Income Taxes

The Company follows the asset and liability method in accounting for income taxes in accordance with ASC 740, Income Taxes . 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, operating losses and tax credit carryforwards.

The Company periodically evaluates deferred tax assets and recognizes a valuation allowance based on the estimate of the amount of such deferred tax assets which the Company believes does not meet the more-likely-than-not recognition criteria. At December 31, 2015 and 2014, it has been concluded that no deferred tax asset valuation allowance is necessary.

The Company evaluates uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. No liability for material uncertain tax positions existed as of December 31, 2015 or 2014.

Share-Based Payments

The Company accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation , which requires companies to recognize in the statement of operations all share-based payments granted to employees based on their fair value. Share-based compensation is recognized by the Company on a straight-line basis over the requisite service period, which approximates the option vesting period of three years.

3. Acquisitions and Divestitures

In March 2014 the Company acquired additional working interests in four wells and approximately 1,240 net acres in the Eagle Ford Shale trend. The acquired assets are located in La Salle County. The Company paid approximately $2,385,000 to acquire the acreage. $750,000 was allocated to proved properties, while $1,635,000 was allocated to unproved properties.

In March 2014 the Company acquired an additional 15,232 gross / 13,156 net acres in the Eagle Ford Shale trend. The acquired assets are located in La Salle, Frio, Wilson, Brazos and Robertson counties. The Company paid approximately $70,737,000 to acquire the acreage. $58,490,000 of the purchase price was allocated to proved properties, while $12,247,000 was allocated to unproved properties. Virtually all of the properties will be operated by Lonestar.

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Notes to Consolidated Financial Statements

As of December 31, 2015, the following derivative transactions were outstanding:

Instrument	Total Volume	Settlement Period	Fixed Price

Oil – WTI Fixed Price Swap	205,000 BBL	January – December 2016	84.45
Oil – WTI Fixed Price Swap	309,000 BBL	January – December 2016	90.45
Oil – WTI Fixed Price Swap	135,600 BBL	January – December 2016	63.20
Oil – WTI Fixed Price Swap	183,400 BBL	January – December 2016	56.90

Instrument	Total Volume	Settlement Period	Puts		Calls

Oil — 3 Way Collar	365,100 BBL	January – December 2017	$	40.00 / 60.00	$	85.00

The above derivative contracts aggregate to 833,000 barrels or 2,276 barrels of oil per day for 2016 and 365,100 barrels or 1,000 barrels of oil per day for 2017. All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the consolidated statement of operations in gain or loss on derivative financial instruments.

As of December 31, 2015 and 2014, all of the Company’s economic derivative hedge positions were with large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features.

6. Fair Value Measurements

In accordance with ASC 820, Fair Value Measurements and Disclosures , fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. ASC 820 prioritizes the inputs used in measuring fair value into the following fair value hierarchy:

Level 1 — Quoted prices for identical assets or liabilities in active markets.

Level 2 — Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement falls in its entirety is determined based on the lowest level input that is significant to the measurement in its entirety.

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Notes to Consolidated Financial Statements

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2015 and 2014, for each fair value hierarchy level:

	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
December 31, 2015
Assets:
Commodity derivatives	$	—	$	36,082,846	$	—	$	36,082,846
Liabilities:
Commodity derivatives	—		—		—		—

Total	$	—	$	36,082,846	$	—	$	36,082,846

December 31, 2014
Assets:
Commodity derivatives	$	—	$	43,758,555	$	—	$	43,758,555
Liabilities:
Commodity derivatives	—		—		—		—

Total	$	—	$	43,758,555	$	—	$	43,758,555

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2015 and 2014 periods.

7. Oil and Gas Properties

A summary of oil and gas properties as of December 31, follows:

	2015			2014

Proved properties and equipment	$	584,691,945		$	495,954,566
Unproved properties	70,298,349			65,725,668
Less accumulated depreciation, depletion, and amortization	(166,890,697		)	(80,600,959		)

	$	488,099,597		$	481,079,275

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Notes to Consolidated Financial Statements

The Company recorded impairment of oil and gas properties of $28,623,000 and $5,478,000 for the years ended December 31, 2015 and 2014, respectively, which is included in accumulated depreciation, depletion, and amortization.

During 2015, the sustained deterioration in the long-term outlook for commodity prices was a triggering event that requiring us to perform impairment testing of our assets that are sensitive to commodity prices. The impairment testing of our long-lived assets was based upon a two-step process as prescribed in the accounting standards.

Step one was performed on each of our oil and gas producing regions and involved a determination as to whether the property’s net book value is expected to be recovered from the estimated undiscounted future cash flows for each respective region. To compute estimated future cash flows, we used our independent reserve engineers’ estimates of proved and probable reserves.

For those regions that failed the impairment test’s first step, we then made a fair market value assessment using discounted cash flow analysis. Based on these results, we recognized $19,696,000 of impairment on those regions where the carrying value exceeded its estimated fair market value.

In addition, during 2015, we recorded a $8,927,000 impairment of undeveloped, unproven properties in Gonzales County. Our independent reserve engineers’ estimates for this region did not include any probable or possible reserves, therefore, it was necessary to impair the remaining net book value of undeveloped, unproven properties for this region.

8. Recently Issued Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. This ASU is effective for the annual period ending after December 15, 2016, and for annual interim periods thereafter. Early adoption is permitted. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements.

In November 2015, the FASB issued ASU No. 2015-17 to simplify income tax accounting. The update requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. This update is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and may be adopted earlier on a voluntary basis. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements — Going Concern” (Subtopic 205-40). This ASU provides guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

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Notes to Consolidated Financial Statements

enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but only for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method of adoption. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and the method of adoption.

9. Asset Retirement Obligations

Pursuant to ASC 410 , Asset Retirement Obligations, the Company recognizes the fair value of its asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets, which approximated $6,927,000 as of December 31, 2015.

The liability has been accreted to its present value as of December 31, 2015. The Company evaluated its wells and has determined a range of abandonment dates through December 2069.

The following represents a reconciliation of the asset retirement obligations:

	Amount

Asset retirement obligations at December 31, 2013	$	5,937,118
Wells drilled during the year	543,555
Wells acquired during the year	965,917
Wells sold during the year	(482,081		)
Accretion of discount	201,076
Wells plugged and abandoned during the year	(330,970		)

Asset retirement obligations at December 31, 2014	6,834,615

Wells drilled during the year	330,969
Wells acquired during the year	176,156
Wells sold during the year	(5,421		)
Accretion of discount	214,335
Wells plugged and abandoned during the year	(63,153		)

Asset retirement obligations at December 31, 2015	$	7,487,501

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Notes to Consolidated Financial Statements

10. Accrued Liabilities

The accrued liabilities consist of the following at December 31:

	2015		2014

Bonus payable	$	1,432,768	$	1,848,612
Severance and vacation payable	28,388		283,540
Accrued interest	4,420,317		4,149,105
Accrued rent	409,643		489,191
Accrued expenses	1,401,080		4,592,152
Other	583,890		242,520

	$	8,276,086	$	11,605,120

11. Income Taxes

The current and deferred components of income tax expense (benefit) are as follows:

Years Ended December 31,	2015			2014

Current tax expense (benefit)
Federal	$	287,855		$	112,621
State	74,324			81,936

Deferred tax expense (benefit)
Federal	(15,130,060		)	21,592,426
State	(353,007		)	644,739

Income tax expense (benefit)	$	(15,120,888	)	$	22,431,722

Total income tax (benefit)/expense differs from the amounts computed by applying the U.S. statutory federal income tax rate to income (loss) before income taxes as a result of state income taxes, certain permanent differences and valuation allowances.

The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated:

Years Ended December 31,	2015			2014

Expected income tax provision (benefit) at statutory rate	$	(14,858,849	)	$	20,614,073
State tax, tax effected	10,536			675,733
Other	(39,646		)	833,016
Rate difference	(232,929		)	308,900
Actual income tax provision	$	(15,120,888	)	$	22,431,722

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Notes to Consolidated Financial Statements

The tax effects of the Company’s temporary differences that give rise to significant portions of the deferred tax assets and liabilities are presented below:

December 31,	2015			2014

Deferred tax assets:
Net operating loss carryforward	$	77,507,544		$	64,772,240
Severance costs	—			96,679
Organizational expenses	57,439			58,187
Stock based compensation	2,431,147			1,522,325
Intangibles	775,719			869,594
Other	1,418,801			24,207

	81,190,650			67,343,232
Deferred tax liabilities:
Oil and gas properties and other property and equipment, principally due to intangible drilling costs	(86,789,694		)	(84,371,190		)
Unrealized hedging gain	(11,414,232		)	(14,482,786		)

Net deferred tax liabilities	$	(16,013,276	)	$	(31,510,744	)

The net operating loss carryforward as of December 31, 2015, approximates $222,656,000 and begins to expire in 2030. The deferred tax asset recorded for the net operating losses does not include $2,200,000 of deductions for excess stock-based compensation. In January 2013, the Company experienced an ownership change as defined in Section 382 of the Internal Revenue Code of 1986, as amended. The provisions of Section 382 apply an annual limit to the amount of the net operating loss carryforward that was incurred prior to the ownership change that can be used to offset future taxable income beginning with the 2013 taxable year. Management believes that the Company’s net operating losses will be fully utilized during the loss carryforward period. The Company has approximately $10,810,000 of percentage depletion carryover which has no expiration.

The Company files income tax returns in the United States federal jurisdiction and in various state jurisdictions. At December 31, 2015, there are no current examinations of federal or state jurisdictions in progress. The Company’s income tax returns related to fiscal years ended December 31, 2010 through 2015 remain open to possible examination by the tax authorities. The Company has not recorded any interest or penalties associated with uncertain tax positions.

The Parent files income tax returns in Australia. Management is not aware of a corporate tax implication as a result of the redomiciliation of the Parent to the United States via an Australian Scheme of Arrangement.

12. Long-Term Debt

The Company’s debt consists of the following:

December 31,	2015			2014

Revolving credit facility	$	87,000,000		$	49,000,000
8.75% senior notes	220,000,000			220,000,000
Less discount on 8.75% senior notes	(3,575,000		)	(4,675,000		)
Other	285,512			288,529

	$	303,710,512		$	264,613,529

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Notes to Consolidated Financial Statements

Senior Revolving Credit Facility

In March 2013, the Company entered into a $400,000,000 syndicated credit facility agreement (“revolving credit facility”) with Wells Fargo Bank (as Administrative Agent). The initial borrowing base was set at $105,000,000. The borrowing base shall be re-determined semi-annually based on the credit agreement, and such re-determined borrowing base shall become effective and applicable on April 1 and October 1 of each year commencing October 1, 2013. The revolving credit facility matures on March 14, 2018. As of December 31, 2014, $49,000,000 was borrowed under the revolving credit facility. The borrowing base as of December 31, 2014 was $150,000,000.

The revolving credit facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. The Company has not drawn any advances on the letter of credit as of December 31, 2014. The revolving credit facility provides for a commitment fee of 0.5% based on the unused portion of the borrowing base under the revolving credit facility.

In June 2013, the Company entered into a $35,000,000 second lien term loan agreement (“2 nd lien facility”) with Wells Fargo Energy Capital, Inc. (as Administrative Agent). The 2 nd lien facility provides for a commitment fee of 0.75% based on the unused portion of the commitment amount under the 2 nd lien facility. The 2 nd lien facility matures on September 14, 2018. In February 2014, the 2 nd lien facility was amended increasing the commitment amount to $55,000,000. In April 2014, the 2 nd lien facility was fully paid and subsequently terminated.

On July 28, 2015, the Company closed a new $500,000,000 Senior Secured Credit Facility which replaced the $400,000,000 Wells Fargo led syndicated facility outlined above. The new facility was arranged by Citibank, N.A. and features an expanded borrowing base of $180,000,000 as of December 31, 2015, which is an increase over the $150,000,000 borrowing base available under the Wells Fargo led facility at December 31, 2014. The new facility provides additional liquidity for the Company and a lower interest rate. The new rate is a 25 basis point improvement over the LIBOR interest rate spread. The new facility provides for an extension in the maturity date to

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Notes to Consolidated Financial Statements

October 16, 2018, which represents a seven month extension over the Wells Fargo led facility. The financial covenants contained in this new facility are substantially the same as the previous facility. As of December 31, 2015, the Company was in compliance with all covenants including all financial ratios under the Citibank led facility. As of December 31, 2015, $87,000,000 was borrowed under the Citibank led revolving credit facility.

8.75% Senior Notes

Year	Percentage
2016	106.563	%
2017	104.375	%
2018 and thereafter	100.000	%

In addition, upon a change of control of the Company, holders of the Notes will have the right to require the the Company to repurchase all or any part of their Notes for cash at a price equal to 101% of the aggregate principal amount of the Notes repurchased, plus any accrued and unpaid interest. The Notes were issued under and governed by an Indenture dated April 4, 2014, between the Company, Wells Fargo Bank, National Association, as trustee and the Company’s subsidiaries named therein as guarantors (the “Indenture”). The Indenture contains covenants that, among other things, limit the ability of the Company and its subsidiaries to: incur indebtedness; pay dividends or make other distributions on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; and merge with or into other companies or transfer substantially all of the Company’s assets.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. During 2014, the Company capitalized approximately $3.5 million in costs associated with the issuance of the Notes and costs incurred for amendments to the Company’s Senior Revolving Credit Facility. With the payoff and termination of the 2nd lien facility, the Company expensed approximately $700,000 of debt issuance costs. At December 31, 2015 and 2014, the Company had approximately $2,900,000 and $3,300,000, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt.

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Notes to Consolidated Financial Statements

13. Commitments and Contingencies

Employment Agreements

Each of the employment agreements to which our executives were a party expired as of December 31, 2015. Currently none of our executive officers are party to any employment agreement or compensatory arrangement, other than customary indemnification agreements.

Litigation

The Company is subject to certain claims and litigation arising in the normal course of business. In the opinion of management, the outcome of such matters will not have a materially adverse effect on the consolidated results of operations or financial position of the Company.

Environmental Remediation

Various federal, state, and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company’s operations and the costs of its oil and gas exploration, development, and production operations. The Company does not anticipate that it will be required in the near future to expend significant amounts in relation to the consolidated financial statements taken as a whole by reason of environmental laws and regulations, and appropriately no reserves have been recorded.

Lease Agreement

The Company entered into an operating lease agreement for its primary facility in October 2014. The lease will expire in October 2021. Future minimum annual lease payments are as follows:

	Amount

2016	$	478,040
2017	455,600
2018	411,768
2019	422,301
2020	432,835
Thereafter	368,011

Total	$	2,568,555

Rent expense was $404,000 and $337,000 for the years ended December 31, 2015 and 2014, respectively. Included in rent expense for 2014 was $88,000 representing the acceleration of the office rent for our previous Fort Worth corporate office that was subleased in December 2014.

Rig Contract

As of December 31, 2015, the Company had one drilling rig under contract. The contract provides for a drilling rate that is indexed on a monthly basis to the West Texas Intermediate (Cushing) average price for that particular month. The current daily drilling rate is $19,000. The rig contract terminates on July 20, 2016. The early termination fee is equal to 75% of the highest month operating rate earned during the 2016 contract period times the number of days remaining on the contract term. Using the $19,000 daily rate, as of December 31, 2015 the minimum remaining commitment per the terms of the agreement is approximately $3.8 million.

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Notes to Consolidated Financial Statements

Stock Option Activity

For the year ended December 31, 2015, no stock options were exercised. The following tables summarize certain information related to outstanding stock options under the 2012 Plan as of and for the years ended December 31, 2015 and 2014:

	Shares		Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term (in years)

Options outstanding at December 31,2013	1,477,685		$	16.00	3.0
Granted	410,822		18.00		3.0
Exercised	—		—		—
Canceled/Expired	(24,667	)	18.00		1.5
Forfeited	(249,570	)	15.00		2.0
Outstanding at December 31, 2014	1,614,270		16.00		2.0
Options vested and exercisable at December 31, 2014	970,155		$	16.00	2.0

Granted	160,000		10.00		1.0
Exercised	—		—		—
Canceled/Expired	(50,000	)	12.00		—
Forfeited	(24,398	)	12.00		—
Outstanding at December 31, 2015	1,699,872		15.50		1.0
Options vested and exercisable at December 31, 2015	1,615,372		$	15.50	1.0

	Shares		Weighted Average Fair Value per Share		Weighted Average Exercise Price per share		Weighted Average Remaining Contractual Term (in years)

Outstanding non-vested options at December 31, 2013	882,456		$	11.50	$	15.00	3.0
Granted	410,822		4.50		18.00		3.0
Vested	(399,593	)	4.50		16.00		3.0
Forfeited	(249,570	)	4.50		15.00		3.0
Outstanding non-vested options at December 31, 2014	644,115		$	4.50	$	16.00	2.0

Granted	160,000		2.40		10.00		1.0
Vested	(695,217	)	4.00		15.50		1.0
Forfeited	(24,398	)	4.50		15.50		—
Outstanding non-vested options at December 31, 2015	84,500		$	4.50	$	15.50	1.0

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Lonestar Resources Limited

Notes to Consolidated Financial Statements

Stock-Based Compensation Expense

For the years ended December 31, 2014 and 2013, the Company recorded stock-based compensation expense of $2,585,000 and $1,938,000, respectively.

As of December 31, 2015, the Company had approximately $380,000 of unrecognized compensation cost related to unvested stock options, which is expected to be amortized over 2016.

15. Earnings Per Share

Lonestar Resources Limited had outstanding ordinary common shares (prior to the reorganization) of 15,044,051 at December 31, 2015 and 14,661,004 at December 31, 2014. Each share entitles the holder to participate in dividends and the proceeds of winding up of the Company in proportion to the number of, and amounts paid on, the shares held. Each share is also entitled to one vote at a stockholder meeting either in person or by proxy.

UNAUDITED PRO FORMA EARNINGS PER SHARE (AFTER REORGANIZATION)

	2015			2014

Net income (loss) per common share:
Basic	$	(3.63	)	$	4.97
Diluted	(3.63		)	4.84

Weighted average common shares outstanding:
Basic	7,522,025			7,330,602
Diluted	7,522,025			7,534,805

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Lonestar Resources Limited

Notes to Consolidated Financial Statements

16. Related Party Activities

During the years ended December 31, 2015 and 2014 the Company paid dividends to its Parent of approximately $308,000 and $637,000, respectively.

Butterfly Flaps, Ltd, a company in which Dr. Christopher Rowland (a director of Lonestar) owns an interest, has performed consultancy work for Lonestar since 2013 covering various strategic, tax structuring and investor matters at a cost of approximately $25,000 per quarter.

New Tech Global Ventures, LLC, a company in which Daniel R. Lockwood (a director of Lonestar) owns a limited partnership interest, has provided field engineering staff and consultancy services for Lonestar since 2013. The total cost for such services was approximately $938,000 and $2,300,000 in 2015 and 2014, respectively.

Mitchell Wells, who has been a Director of Lonestar Resources Limited since December 2014, has provided consultancy services as its Company Secretary since January 2013. These services have been provided through BlueSkye Pty Ltd, for which Mr. Wells is the sole Director and shareholder. BlueSkye Pty Ltd was paid $143,000 for 2015 and $182,000 for 2014. He has not received any additional compensation for his service as a Director.

17. Supplemental Information on Oil and Natural Gas Exploration and Production Activities (unaudited)

Capitalized Costs

The following table presents the Company’s aggregate capitalized costs relating to oil and gas activities at the end of the periods indicated:

December 31,	2015			2014

Oil and natural gas properties:
Proved properties and equipment	$	577,764,738		$	489,472,814
Unproved properties	70,298,349			65,725,668
Capitalized asset retirement cost	6,927,207			6,481,752

Less:
Accumulated depletion and amortization	(133,080,366		)	(75,122,695		)
Property impairment	(33,810,331		)	(5,478,264		)

Total	$	488,099,597		$	481,079,275

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Lonestar Resources Limited

Notes to Consolidated Financial Statements

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Years ended December 31,	2015		2014

Property acquisition costs :
Unproved properties	$	7,327,635	$	12,247,000
Proved properties	1,395,862		58,731,282
Exploration costs	—		—
Development costs	85,458,433		164,180,576

Total costs incurred	$	94,181,930	235,158,858

Results of Operations

The following table sets for the results of operations from oil and gas producing activities for the years ended December 31, 2015 and 2014.

Years ended December 31,	2015			2014

Oil and gas producing activities:
Oil sales	$	70,739,269		$	104,233,379
Natural gas sales	6,823,019			7,589,599
Natural gas liquids sales	1,928,068			3,803,582
Lease operating and gas gathering	(17,860,216		)	(16,631,611		)
Production, ad valorem and severance taxes	(4,981,826		)	(7,123,332		)
Accretion of asset retirement obligations	(214,335		)	(201,076		)
Depreciation, depletion and amortization	(58,827,705		)	(40,521,546		)
Property impairment	(28,622,961		)	(5,478,264		)
Results of operations from oil and gas producing activities	$	(31,016,687	)	$	45,670,731

Depletion rate per BOE	$	25.16		$	24.78

Crude Oil and Natural Gas Reserves

Net Proved Reserve Summary

The reserve information presented below is based upon estimates of net proved oil and gas reserves that were prepared by the independent petroleum engineering firms of W.D. Von Gonten & Co. for the evaluation of the Company’s Eagle Ford Shale properties and LaRoche Petroleum Consultants, Ltd. for the evaluation of the Company’s conventional assets. All of the Company’s reserves are located in the United States.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs of the date the estimate is made). The project to extract the hydrocarbons must have commenced or the interest owner must be reasonably certain that it will commence within a reasonable period of time.

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Lonestar Resources Limited

Notes to Consolidated Financial Statements

Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimate are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.

The following information table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2015 and 2014.

	Oil (BBL)		NGLs (BBL)		Gas (MCF)		BOE (1)

Net proved reserves
Reserves at December 31, 2013	13,483,483		1,841,457		17,373,143		18,220,463
New discoveries and extensions	2,462,295		321,301		2,528,029		3,204,934
Purchase of reserves in place	9,648,101		484,493		3,655,020		10,741,764
Reserves sold	(252,200	)	—		(5,632	)	(253,139	)
Revisions of prior year estimates	(532,522	)	551,078		4,106,883		703,038
Production	(1,198,279	)	(154,215	)	(1,689,029	)	(1,633,999	)
Reserves at December 31, 2014	23,610,878		3,044,114		25,968,414		30,983,061

New discoveries & extensions	6,575,775		4,281,649		34,155,539		16,550,014
Purchase of reserves in place	1,541,828		297,634		2,344,083		2,230,142
Reserves sold	—		—		—		—
Revisions of prior year estimates	(6,637,821	)	(146,113	)	(2,562,392	)	(7,210,998	)
Production	(1,539,505	)	(322,808	)	(2,923,787	)	(2,349,611	)
Reserves at December 31, 2015	23,551,155		7,154,476		56,981,857		40,202,608

Proved Developed Reserves:
December 31, 2013	6,195,280		638,632		8,287,574		8,215,173
December 31, 2014	9,184,925		1,211,551		11,990,723		12,394,930
December 31, 2015	8,357,772		2,020,216		17,534,695		13,300,438

Proved Undeveloped Reserves:
December 31, 2013	7,288,203		1,202,825		9,085,569		10,005,290
December 31, 2014	14,425,953		1,832,563		13,977,691		18,588,131
December 31, 2015	15,193,383		5,134,260		39,447,162		26,902,170

(1) BOE (barrels of oil equivalent) is calculated by converting 6 MCF of natural gas to 1 BBL of oil. A BBL (barrel) of oil is one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

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Lonestar Resources Limited

Notes to Consolidated Financial Statements

Standardized Measure of Discounted Future Net Cash Flows

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented.

For the years ended December 31, 2015 and 2014, calculations were made using average prices of $50.28 and $94.99 per barrel of crude oil, respectively, and $2.59 and $4.35 per MCF of natural gas, respectively. Prices and costs are held constant for the life of the wells; however, prices are adjusted by well in accordance with sales contracts, energy content quality, transportation, compression and gathering fees, and regional price differentials.

These assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC, and do not necessarily reflect the Company’s expectations of the actual net cash flow to be derived from those reserves, nor the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

A 10% annual discount rate is used to reflect the timing of the future net cash flows relating to proved reserves.

The standardized measure of discounted future net cash flows as of December 31, 2015 and 2014 were as follows:

December 31,	2015			2014

Future cash flows	$	1,363,349,591		$	2,389,844,493
Future costs
Production	(456,088,889		)	(649,398,768		)
Development	(289,026,333		)	(320,222,400		)

Future inflows before income tax	618,234,369			1,420,223,325
Future income taxes	(66,565,870		)	(353,602,580		)

Future net cash flows	551,668,499			1,066,620,745
10% annual discount for estimated timing of cash flows	(283,242,412		)	(517,581,023		)

Standardized measure of discounted future net cash flows	$	268,426,087		$	549,039,722

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Table of Contents

Lonestar Resources Limited

Notes to Consolidated Financial Statements

Changes in the Standardized Measure of Discounted Future Net Cash flows Relating to Proved Crude Oil and Nature Gas Reserves were as follows for the years indicated:

December 31,	2015			2014

Standardized measure at beginning of year	$	549,039,722		$	302,771,526
Extensions and discoveries and improved recovery net of future production and development costs	74,142,661			88,919,601
Purchase of minerals in place	11,519,608			270,331,369
Accretion of discount	70,582,116			41,871,778
Net change in sales price, net of production costs	(501,189,743		)	(38,540,796		)
Changes in estimated future development costs	56,188,859			(9,274,717		)
Changes of production rates (timing) and other	125,681,828			12,731,855
Revisions of quantity estimates	(191,356,505		)	18,066,206
Net change in income taxes	130,906,060			(40,835,170		)
Sales net of production costs	(57,088,519		)	(91,571,228		)
Sales of minerals in place	—			(5,430,702		)
Net increase (decrease)	(280,613,635		)	246,268,196

Standardized measure at end of year	$	268,426,087		$	549,039,722

18. Subsequent Events

In preparing the consolidated financial statements, management has evaluated all subsequent events and transactions for potential recognition or disclosure through the date the accompanying consolidated financial statements were issued.

19. Reorganization

In connection with the planned reorganization, a new corporate entity was formed, Lonestar Resources U.S. Inc., which immediately prior to the reorganization will acquire the Parent via an Australian Scheme of Arrangement. As a result, certain accounting policies have been adopted in these financial statements as if the Company were a public company. These include earnings per share, segment reporting and supplemental oil and gas disclosures.

F- 46

Delaware		81-0874035
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

600 Bailey Avenue, Suite 200, Fort Worth, TX		76107
(Address of principal executive offices)		(Zip Code)

Large accelerated filer o		Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company x

		Lonestar Resources US Inc.


Date:	June 9, 2016	By:	/s/ Frank D. Bracken, III
			Frank D. Bracken, III Chief Executive Officer

	Page

Consolidated Balance Sheets as of March 31, 2016 (unaudited) and December 31, 2015	F-2
Unaudited Consolidated Statements of Operations and Other Comprehensive Income (Loss) for three months ended March 31, 2016 and 2015	F-4
Unaudited Consolidated Statements of Changes in Stockholders’ Equity for the three months ended March 31, 2016	F-5
Unaudited Consolidated Statements of Cash Flows for the three months ended March 31, 2016 and 2015	F-6
Notes to Unaudited Consolidated Financial Statements	F-7

Report of Independent Registered Public Accounting Firm	F-18
Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014	F-19
Consolidated Statements of Operations and Other Comprehensive Income (Loss) for the years ended December 31, 2015 and 2014	F-21
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2015 and 2014	F-22
Consolidated Statements of Cash Flows for the years ended December 31, 2015 and 2014	F-23
Notes to Consolidated Financial Statements	F-24

Title of each class to be so registered		Name of each exchange on which each class is to be registered

Class A Voting Common Stock, par value $0.001 per share		The Nasdaq Stock Market LLC

		Page #

Item 1.	Business	8

Item 1A.	Risk Factors	30

Item 2.	Financial Information	52

Item 3.	Properties	73

Item 4.	Security Ownership of Certain Beneficial Owners and Management	78

Item 5.	Directors and Executive Officers	80

Item 6.	Executive Compensation	85

Item 7.	Certain Relationships and Related Transactions and Director Independence	90

Item 8.	Legal Proceedings	91

Item 9.	Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters	91

Item 10.	Recent Sales of Unregistered Securities	92

Item 11.	Description of Registrant’s Securities to be Registered	93

Item 12.	Indemnification of Directors and Officers	94

Item 13.	Financial Statements and Supplementary Data	95

Item 14.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	95

Item 15.	Financial Statements and Exhibits	96

	BORROWER :

	LONESTAR RESOURCES AMERICA INC.

	By:	/s/ Frank D. Bracken III
	Name:	Frank D. Bracken III
	Title:	Chief Executive Officer

ADMINISTRATIVE AGENT :

CITIBANK, N.A.
as Administrative Agent

By:		/s/ Jarrod Bourgeois
Name:		Jarrod Bourgeois
Title:		Senior Vice President

LENDERS :

CITIBANK, N.A.

By:	/s/ Jarrod Bourgeois
Name:	Jarrod Bourgeois
Title:	Senior Vice President

	ABN AMRO CAPITAL USA LLC

	By:	/s/ Darrell Holley
	Name:	Darrell Holley
	Title:	Managing Director

	By:	/s/ David Montgomery
	Name:	David Montgomery
	Title:	Executive Director

	TEXAS CAPITAL BANK, N.A.

	By:	/s/ Grant W. Leigh
	Name:	Grant W. Leigh
	Title:	Senior Vice President

	BOKF, N.A. dba Bank of Texas

	By:	/s/ Colin Watson
	Name:	Colin Watson
	Title:	Vice President

	COMERICA BANK

	By:	/s/ Robert C. Pitcock
	Name:	Robert C. Pitcock
	Title:	Relationship Manager

	COMPASS BANK

	By:	/s/ Blake Kirshman
	Name:	Blake Kirshman
	Title:	Senior Vice President

	BARCLAYS BANK PLC

	By:	/s/ Vanessa A. Kurbatskiy
	Name:	Vanessa A. Kurbatskiy
	Title:	Vice President

	BORROWER:

	LONESTAR RESOURCES AMERICA INC.


	By:	/s/ Frank D. Bracken III
	Name:	Frank D. Bracken III
	Title:	Chief Executive Officer

	BOKF, N.A.


	By:	/s/ Lacey H. Miller
	Name:	Lacey H. Miller
	Title:	Assistant Vice President

	COMPASS BANK


	By:	/s/ Les Werme
	Name:	Les Werme
	Title:	Director