UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

For the fiscal year ended December 31, 2016

OR

Commission File Number 001-37670

 

Lonestar Resources US Inc.

(Exact name of Registrant as specified in its Charter)

 

 

Registrant’s telephone number, including area code: (817) 921-1889

 

Securities Registered Pursuant to Section 12(b) of the Act:

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ☐ NO ☒

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES ☐ NO ☒

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

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). YES ☒ NO ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ☐ NO  ☒

The Registrant was not a public company in the United States as of the last business day of its most recently completed second fiscal quarter and, therefore, cannot calculate the aggregate market value of its voting and non-voting common equity held by non-affiliates as of such date. As of such date, the former parent company of the Registrant’s group of companies, Lonestar Resources Limited, had its ordinary shares listed on the Australian

 

---

 

Securities Exchange (“ASX”). The aggregate market value of the ordinary shares held by non-affiliates of Lonestar Resources Limited, based on the closing price of the shares of such ordinary shares on ASX as of June 30, 2016, was approximately $30.0 million.

The number of shares of the Registrant’s Class A voting common stock outstanding as of March 17, 2017 was 21,822,015.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the Registrant’s 2017 Annual Meeting of Shareholders are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 

 

 

 

---

 

Table of Contents

 

 

 

 

i

---

 

GLOSSARY OF CERTAIN DEFINED TERMS

The terms defined in this section are used throughout this Annual Report on Form 10-K:

“2016 Common Stock Offering.” The offering of our Class A common stock that was completed on December 22, 2016 pursuant to a Registration Statement on Form S-1 (File No. 333-214265), which was declared effective on December 15, 2016.

“3-D seismic.” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used in reference to crude oil, condensate or natural gas liquids.

“Bbl/d.” One stock tank barrel of crude oil, condensate or natural gas liquids per day.

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

“Boe/d.” One barrel of oil equivalent per day.

“British thermal unit” or “Btu.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Class A common stock.” Class A voting common stock of Lonestar Resources US Inc., par value $0.001 per share.

“completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting of abandonment to the appropriate agency.

“condensate.” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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

“development capital.” Expenditures to obtain access to proved reserves and to construct facilities for producing, treating and storing hydrocarbons.

“development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry well” or “dry.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).

“exploitation.” A development or other project which may target proved or unproved reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

“exploratory well.” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

“field.” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

“formation.” A layer of rock which has distinct characteristics that differ from nearby rock.

“GAAP.” Accounting principles generally accepted in the United States.

G-1

---

 

“gross acres” or “gross wells.” The total acres or wells, as the case may be, in which an entity owns a working interest.

“held by production” or “HBP” 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 drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“IRS.” Internal Revenue Service.

“lease operating expense.” All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

“LIBOR.” London Interbank Offered Rate.

“MBbl.” One thousand barrels of crude oil, condensate or NGLs.

“MBoe.” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“Mcf/d.” One thousand cubic feet of natural gas per day.

“MMBbls.” One million stock tank barrels, of 42 U.S. gallons liquid volume, used in reference to crude oil, condensate or natural gas liquids.

“MMBoe.” One million barrels of oil equivalent.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

“natural gas liquids” or “ NGLs.” The combination of ethane, propane, butane, isobutane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

“net acres” or “net wells.” The percentage of total acres or wells, as the case may be, an owner has out of a particular number of gross acres or wells. For example, an owner who has 50% interest in 100 gross acres owns 50 net acres.

“net revenue interest.” An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

“NYMEX.” The New York Mercantile Exchange.

“operator.” The entity responsible for the exploration, development and production of a well or lease.

“present value of future net revenues” or “PV-10.” 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. PV-10 differs from the Standardized Measure because it does not include the effect of future income taxes.

“productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

G-2

---

 

“proved developed reserves.” Proved reserves that can be expected to be recovered:

i. Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or

ii. Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“proved reserves.” 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 regulations —prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence, the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

“proved undeveloped reserves” or “PUDs.” 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.” A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

“recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“reliable technology.” A grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

“reserves.” 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 prospects 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 hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“royalty.” An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

“SEC.” The United States Securities and Exchange Commission.

“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.

G-3

---

 

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

“wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

“working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

“workover.” Operations on a producing well to restore or increase production.

“WTI.” West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or 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.

 

 

 

G-4

---

 

Cautionary Statement Regarding Forward-Looking Statements

This annual report contains statements concerning our intentions, expectations, projections, assessments of risks, estimations, beliefs, plans or predictions for the future, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among others, statements regarding:

 

You generally can identify our forward-looking statements by the words “anticipate,” “believe,” budgeted,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “scheduled,” “should,” or other similar words. Such statements rely on assumptions and involve risks, uncertainties, and other important factors, many of which are beyond our control, including, but not limited to, those relating to a worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, the timing and amount of borrowing base determinations (including determinations by lenders) and availability under our senior secured credit facility, evaluations of us by lenders under our senior secured credit facility, other actions by lenders, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, acquisition risks, availability of equipment and crews, actions by midstream and other industry participants, weather, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our

1

---

 

joint ventures, actions by joint venture parties, results of exploration activities, the availability and completion of land acquisitions, costs of oilfield services, completion and connection of wells, our ability to adhere to our proposed drilling schedule, potential expiration of leases on undeveloped leasehold assets under certain conditions, and other important factors detailed in this annual report.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

Some of the important factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under Part I, “Item 1A. Risk Factors” and in other sections of this annual report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

Certain terms used herein relating to the oil and gas industry are defined in “Glossary of Certain Defined Terms” included above.

Presentation of Information

On July 5, 2016, Lonestar Resources US Inc., a Delaware corporation, acquired all of the issued and outstanding ordinary shares of Lonestar Resources Limited, the former parent company of the Lonestar group of companies, pursuant to a Scheme of Arrangement under Australian law that was approved by the Federal Court of Australia on June 28, 2016, and by Lonestar Resources Limited’s shareholders at a meeting of shareholders, which approval was obtained in March 2016 (the “Reorganization”).  The purpose of the Reorganization was to reorganize the operations of Lonestar Resources Limited, an Australian corporation, into a structure whereby the ultimate parent company of the Lonestar group of companies would be a Delaware corporation.  In connection with the Reorganization, the ordinary shares of Lonestar Resources Limited were delisted from the Australian Securities Exchange, and the Class A common stock of Lonestar Resources US Inc. began trading on the NASDAQ Global Select Market on July 5, 2016 under the ticker symbol “LONE”.

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

Unless the context otherwise requires, references to “Lonestar,” “we,” “us,” “our,” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable. General information about us can be found on our website at www.lonestarresources.com. The information available on or through our website, or about us on any other website, is neither incorporated into, nor part of, this report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings that we make with the SEC, as well as any amendments and exhibits to those reports, will be available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC. Information is also available on the SEC website at www.sec.gov for our U.S. filings.

 

 

 

2

---

 

PART I

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 41,274 gross (34,170 net) acres in what we believe to be the formation’s crude oil and condensate windows as of December 31, 2016. 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 United States, and, as of December 31, 2016, we had no long lived assets located outside the United States.

Our primary operational focus is on our Eagle Ford Shale position in seven Texas counties. Our properties in the Eagle Ford Shale are divided into three distinct regions: 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, 2016, we operated 100% of our Eagle Ford position and approximately 75% of our acreage was held by production, or HBP. Third party engineers have identified 141 gross (118 net) horizontal drilling locations on our Eagle Ford Shale acreages. We also own 44,084 gross (28,655 net) undeveloped acres in the Bakken Three Forks formation in Roosevelt County, Montana, our “West Poplar” property. We are currently evaluating our 2017 budget for this area

We plan to invest the majority of our 2017 capital budget for the horizontal development of our Eagle Ford Shale properties and have allocated between $62 million and $72 million to drilling and completion activities to develop these assets, of which up to $10 million is allocated for leasehold acquisition expenditures. We have historically grown our Eagle Ford leasehold position through organic leasing activities, farm-ins, acquisitions, and other structures. We believe our management team’s extensive experience and our reputation as an operator in the basin provide us with relationships and contacts that could serve as a platform for expanded opportunities to grow our acreage footprint.

We seek to deploy advanced drilling, completion and production techniques across our unconventional acreage with a goal of minimizing completed well costs and maximizing per well hydrocarbon recoveries. Increasingly, we utilize 3-D seismic imaging to plan our lateral programs while utilizing log-based petrophysical analysis to optimize our drilling targets within distinct horizons within the Eagle Ford Shale section. We are also frequently drilling laterals in excess of 7,000 feet in an effort to maximize per-well recoveries and economic returns. Further, we are utilizing thru-bit logging in our laterals to design non-geometric completions which allow for the use of diverters while increasing proppant concentrations in an effort to make our fracture stimulations more effective. Additionally, we employ active choke management to optimize pressure drawdowns in an effort to maximize liquid hydrocarbon recoveries.

The following table presents summary data for each of our primary project areas as of December 31, 2016:

 

  

3

---

 

Our Eagle Ford Shale Properties

Our Eagle Ford Shale net production for the year ended December 31, 2016 was 5,495 Boe/d, comprised of 3,006 Bbls/d of oil, 1,161 Bbls/d of NGLs and 7,967 Mcf/d of natural gas, from 70 gross (62 net) producing wells.

As of December 31, 2016, according to our reserve report, our Eagle Ford Shale properties had proved reserves of 40.5 MMBoe, of which 75% is crude oil and NGLs and 27% is proved developed producing, or PDP. The PV-10⁽¹⁾ of our Eagle Ford proved reserves as of December 31, 2016 was $166.5 million using SEC pricing, and 61% of such PV-10 is PDP. The PV-10 of our Eagle Ford proved reserves as of December 31, 2016 was $382.0 million using NYMEX strip pricing, and 38% of such PV-10 is PDP. See “Summary Historical Reserve and Operating Data”.

Third party engineers have identified 141 gross (118 net) horizontal drilling locations on our acreage of which 68% are expected to be drilled using lateral lengths of or greater than 7,000 feet and 96% are expected to be drilled using lateral lengths of or greater than 5,000 feet.

Western Eagle Ford. As of December 31, 2016, our Western Eagle Ford region was comprised of 15,208 gross (13,413 net) acres in Dimmit, La Salle and Frio Counties. As of December 31, 2016, we operated 100% of this acreage. Approximately 90% of this net acreage is HBP. We plan on allocating between $27.3 million to $42.3 million of our 2017 capital budget to our Western Eagle Ford acreage.

Central Eagle Ford. Our Central Eagle Ford region as of December 31, 2016 was comprised of 10,556 gross (9,866 net) acres in Wilson and Gonzales Counties. As of December 31, 2016, we operated 100% of this acreage. Approximately 77% of this net acreage was HBP. We plan on allocating between $16.0 million to $31.0 million of our 2017 capital budget to this area.

Eastern Eagle Ford. Our Eastern Eagle Ford region as of December 31, 2016, was comprised of 15,510 gross (10,891 net) acres in Brazos and Robertson Counties. Approximately 55% of this net acreage is HBP. As of December 31, 2016, we operated 100% of this acreage. Our Eastern region includes 8,523 gross (5,935) net acres, which are located within the productive limits of the Aguila Vado Eagle Ford Shale Field, and an additional 6,987 gross (4,956) net acres that are under appraisal. We plan on allocating approximately $3.7 million of our 2017 capital budget to our Eastern Eagle Ford acreage.

(1) 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 “Oil and Natural Gas Data—PV-10” below for more information and a reconciliation of PV-10 to our Standardized Measure.

Non-Core Properties

Conventional Texas Assets

We have historically maintained conventional oil and natural gas properties located in 13 counties in Texas, including long-lived reserves in the Canyon, Delaware Sand, Hackberry, Caddo, Cockfield and Jackson formations. As of December 31, 2015, these properties contained approximately 2.2 MMBoe of estimated proved reserves, of which 79% was crude oil. For the year ended December 31, 2016, production from our conventional assets averaged 404 Boe/d which represented 7% of our total net reported production for the year. Consistent with our plan to divest non-core assets and reduce our outstanding indebtedness, on June 15, 2016, we sold a portion of these assets for $2.2 million. On September 26, 2016, we entered into an agreement to sell the remaining assets for $14.0 million, and this transaction closed on October 31, 2016.

4

---

 

Bakken Three Forks Assets

We also have 44,084 gross (28,655 net) undeveloped acres in the Poplar West area of the Bakken Three Forks formation in Roosevelt County, Montana. We expect to pursue a number of farm-in or other structured transactions to bring in a potential exploration partner in this area. We are currently evaluating our 2017 capital budget for this area.

Business Strategies

Our primary business objective is to increase reserves, production and cash flows at 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:

5

---

 

Our Competitive Strengths

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

 

6

---

 

7

---

 

Oil and Natural Gas Data

Estimated Proved Reserves

The following table presents estimated net proved oil, NGLs and natural gas reserves attributable to our properties and the Standardized Measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2016, 2015 and 2014. We employ a technical staff of engineers and geoscientists that perform technical analysis of each producing well and undeveloped location. The staff uses industry accepted practices to estimate, with reasonable certainty, the economically producible oil and gas reserves.  The practices for estimating hydrocarbons in place include, but are not limited to, mapping, seismic interpretation, core analysis, log analysis, mechanical properties of formations, thermal maturity, well testing and flowing bottom hole pressure analysis.  We employ an independent petroleum engineer to estimate 100% of our proved reserves. The data below is based on our reserve report prepared by W.D. Von Gonten & Co. for our Eagle Ford Shale properties and on the reserve report prepared by LaRoche Petroleum Consultants, Ltd. for our conventional properties in the State of Texas. The Standardized Measure and PV-10 amounts shown in the table are 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 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., divested in 2016.

 

8

---

 

 

The data in the table above represent estimates only. Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure amounts shown above should not be construed as the current market value of our estimated oil, NGLs and natural gas reserves. The 10% discount factor used to calculate Standardized Measure, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

PV-10

Certain of our oil and natural gas reserve disclosures included in this Annual Report on Form 10-K 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 above 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.

9

---

 

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

 

 

Reconciliation of Proved Reserves

Our proved developed oil and natural gas reserves decreased from 13.3 MMBoe at December 31, 2015 to 11.0 MMBoe at December 31, 2016 principally due to the sale of our conventional assets, which at December 31, 2015 were 100% PDP.  During the year, we converted 2.4 MMBoe of Proved Undeveloped reserves to the Proved Developed Producing category and added 0.3 MMBoe through drilling on new properties, while producing 1.7 MMBoe during the year ended December 31, 2016.  Our proved developed oil and natural gas reserves experienced revisions of 1.6 MMBoe.

 

 

At December 31, 2016, 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.

 

 

Development of Proved Undeveloped Reserves

At December 31, 2016, our proved undeveloped reserves were approximately 29,542 MBoe, an increase of approximately 2,640 MBoe over our December 31, 2015 estimated proved undeveloped reserves of approximately 26,902 MBoe. In 2016, we added net

10

---

 

proved undeveloped reserves of 6,368 MBoe as a result of drilling and completion activities and 32 MBoe as a result of the acquisition of proved undeveloped reserves. During 2016, approximately 2,435 MBoe of proved undeveloped reserves, as of December 31, 2015, were converted to proved developed reserves as a result of drilling and completion activities during the year, and 1,325 MBoe of reserves were subtracted from our proved undeveloped reserves as a result of revisions in estimates from 2015. During the year ended December 31, 2016, we incurred capital expenditures of approximately $39.4 million to convert these proved undeveloped reserves as of December 31, 2015 to proved developed reserves.

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 40 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 20 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 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, 2016, 2015, and 2014 for the Eagle Ford Shale properties were prepared by W.D. Von Gonten & Co., independent reserve engineers. Our estimated reserves at December 31, 2015 and 2014 for our conventional long-lived,

11

---

 

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 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.

 

Oil and Natural Gas Production Prices and Costs

 

Production, Revenues and Price History

 

The following table sets forth information regarding net production of oil, NGLs and natural gas and certain price and cost information attributable to our properties, for the years ended December 31, 2016, 2015, and 2014.

 

 

 

 

 

 

Drilling Activity

12

---

 

 

The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2016, 2015, and 2014. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.

 

 

The wells are in various states of development or stages of production

 

As of December 31, 2016, we were in process of drilling 3 gross (2.9 net) wells that are not included in the table above.

 

 

Acreage Data

 

The following table sets forth information relating to our leasehold acreage in the Eagle Ford and the Bakken-Three Forks trend. As of December 31, 2016, approximately 75% of our net Eagle Ford acreage was held by production.

 

 

As of December 31, 2016, we had leases across the Eagle Ford Shale representing 4,519 net acres expiring in 2017, 1,421 net acres expiring in 2018, and 1,325 net acres expiring in 2019 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 2017. Our 28,655 net acres in the West Poplar areaare subject to leases expiring in 2017, 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 our West Poplar site, we 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

General

 

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. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

 

 

Marketing and Customers

13

---

 

 

For the year ended December 31, 2016, purchases by our largest four customers accounted for 40%, 21%, 18%, and 10% 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.

 

Transportation

 

During the initial development of our fields, we consider all gathering and delivery infrastructure options in the area of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm or by pipeline. Our natural gas is generally transported from the wellhead to the purchaser’s pipeline interconnection point through our gathering system.

 

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., Halcon 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.

 

Seasonality 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.

 

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.

 

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

14

---

 

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.

 

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%.

 

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 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 Sales and Transportation of 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, 2016, the index will be PPI plus 1.23%.

 

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

15

---

 

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 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 Environmental and Occupational Safety and Health Matters

 

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.

16

---

 

 

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 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 Handling

 

The federal 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 liabilities 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. Following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and as waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs and drilling operations to manage and dispose of generated wastes and a corresponding decrease in their drilling operations, which developments could have a material adverse effect on our business. In addition, 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 cleanup requirements. No such effort has been successful to date.

17

---

 

 

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.

 

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 storm water 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.

 

In May 2015, the EPA issued final rules attempting to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and several other district courts ponder lawsuits opposing implementation of the rule. In January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. On February 28, 2017, President Trump issued an executive order directing the EPA and the Army Corps of Engineers to review and, consistent with applicable law, initiate rulemaking to rescind or revise the rule. On March 6, 2017, the EPA and Army Corps of Engineers published a notice of intent to review and rescind or revise the rule and on March 6, 2017, the U.S. Department of Justice filed a motion with the U.S. Supreme Court requesting the Court to stay the suit regarding which courts should hear challenges to this rule. At this time, it is unclear what impact these actions will have on the implementation of the rule. 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.

 

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. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For example, the EPA also issued CAA regulations relevant to hydraulic fracturing in 2012, including a new source performance standard for volatile organic chemicals (“VOCs”) and sulfur dioxide (“SO2”) 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.

 

In June 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s final rules include the NSPS to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on VOC emissions to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and VOC sources include hydraulically fractured (or re-fractured) oil

18

---

 

and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. Several states and industry groups have filed suit before the D.C. Circuit challenging EPA’s implementation of the methane rule and legal authority to issue the methane rules.  The EPA has also announced that it intends to impose methane emission standards for existing sources but, to date, has not yet issued a proposal.  The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In addition, in October 2015, the EPA issued a final rule under the CAA, lowering the NAAQS for ground-level ozone from the current standard of 75 ppb for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. The final rule became effective on December 28, 2015. States are expected to implement more stringent permitting and pollution control requirements as a result of this new final rule, which could apply to our operations.  

 

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.

 

Regulation of GHG Emissions

 

Climate and related energy policy, laws and regulations could change quickly, and substantial uncertainty exists about the nature of many potential developments that could impact the sources and uses of energy. In December 2015, the United States and 194 other countries, adopted the Paris Agreement, committing to work towards limiting global warming and agreeing to a monitoring and review process of GHG emissions. 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. On October 4, 2016, the E.U. ratified the Paris Agreement, thus meeting the threshold for the agreement to come into force.

 

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. EPA also published a final rule in June 2016 controlling methane gas and VOC emissions from crude oil and natural gas sources. Several states and industry groups have filed suit before the D.C. Circuit challenging the EPA’s implementation of the methane rule and legal authority to issue the methane rules. The EPA also announced in November 2016 that it intends to propose similar standards for existing sources. However, on March 3, 2017, EPA announced that it was withdrawing the ICR so that the agency may further assess the need for the information that it was collecting through the request. The EPA also finalized rules in 2016 that clarify when crude oil and natural gas sites should be aggregated for purposes of air permitting, which could increase our compliance and permitting costs. 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.

 

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. 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

19

---

 

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.

 

Hydraulic Fracturing Activities

 

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.

 

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 SO2 emissions with expanded applicability to natural gas operations and new national emission standards for hazardous air pollutants standards for air toxics. Also, in June 2016, the EPA finalized rules to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. 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. In addition, federal agencies have started to assert regulatory authority over the process.  In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. The U.S. Department of the Interior has likewise developed comprehensive regulations for hydraulic fracturing on federal land, which were successfully challenged by industry groups and are now under appellate review.

 

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. A majority of states around the country, including 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. For example, on October 28, 2014, the Texas Railroad Commission, or TRC, published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well.

 

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.

 

ESA and Migratory Birds

 

The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. 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 and the Migratory Bird Treaty Act. However, the designation of previously unidentified endangered or threatened species or habitats in areas where our operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could have a material adverse impact on the value of our leases.

20

---

 

 

National Environmental Policy Act

 

Our operations on federal lands are subject to the National Environmental Policy Act, or NEPA. Under NEPA, federal agencies, including the Department of Interior must evaluate major agency actions having the potential to significantly impact the environment. This review can entail a detailed evaluation including an Environmental Impact Statement. This process can result in significant delays and may result in additional limitations and costs associated with projects on federal lands.

 

OSHA

 

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 March 2016, OSHA amended its legal requirements, publishing a final rule that established a more stringent permissible exposure limit for exposure to respirable crystalline silica and provided other provisions to protect employees, such as requirements for exposure assessment, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recordkeeping. This final rule became effective in June 2016. However, several industry groups have filed suit in the D.C. Circuit to halt implementation of the rule. 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.

 

Related Permits and Authorizations

 

Many environmental laws require us to obtain permits or other authorizations from state, federal and/or Tribal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

 

We have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We did not have any material capital or other nonrecurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2016, nor do we anticipate that such expenditures will be material in 2017.

 

Related Insurance

 

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

 

Employees

 

As of December 31, 2016, we had 44 employees, including seven engineers and geoscientists, four land professionals and ten 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.

 

Formation Transactions

Lonestar Resources US Inc. was incorporated Delaware in December 2015 for purposes of effecting our corporate reorganization, which was completed in July 5, 2016 (the “Reorganization”), pursuant to a Scheme Implementation Agreement (the “Scheme”), dated December 28, 2015, between the Company and Lonestar Resources Limited (our “Predecessor”), an Australian company and our former parent company.

21

---

 

Prior to the Reorganization, our business was owned and operated under our Predecessor, whose ordinary shares were listed on the Australian Securities Exchange (“ASX”). Pursuant to the Scheme, the Company acquired all of the issued and outstanding ordinary shares of our Predecessor, and each of our Predecessor’s shareholders received one share of our Class A common stock for every two ordinary shares of our Predecessor such shareholder held.

In connection with the Reorganization, we filed a registration statement on Form 10 (“Form 10”) to register our Class A common stock pursuant to Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Following the effectiveness of the registration statement and in connection with the completion of the Reorganization, the ordinary shares of our Predecessor were delisted from the ASX, and our Class A common stock was listed on the NASDAQ Global Select market (“NASDAQ”).

Recent Events

Deleveraging Initiative

Securities Purchase Agreement

On August 2, 2016, Lonestar Resources America, Inc. (“LRAI”) and the Company entered into a Securities Purchase Agreement with Juneau Energy, LLC, as initial purchaser (“Juneau”), Leucadia National Corporation (“Leucadia”), as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share (the “Warrants”). The initial sale of $10,000,000 aggregate principal amount of Second Lien Notes closed on August 4, 2016.

The Second Lien Notes are secured by second-priority liens on substantially all of LRAI’s and its subsidiaries’ assets to the extent such assets secure obligations under LRAI’s $500,000,000 Senior Secured Credit Facility, entered into on July 28, 2015 (the “Senior Secured Credit Facility”). During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 760,000 shares of its Class A common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance. The warrants were adjusted to fair value at December 31, 2016 which resulted in an unrealized gain on warrants of approximately $0.6 million. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of LRAI’s $220,000,000 of 8.750% Senior Unsecured Notes due April 15, 2019 (the “8.750% Senior Notes”) in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.

 

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering.

Equity Backstop Commitment

In addition, pursuant to the Securities Purchase Agreement with Juneau and Leucadia, in the event that the Company elected to pursue an equity offering prior to December 31, 2016, Leucadia agreed to purchase the number of shares of Class A common stock equal to (a) $20,000,000 (or such lesser amount as the Company requests) divided by (b) the offering price to investors in a registered public offering of securities that is completed on or before December 31, 2016 (the “Equity Backstop Commitment”). Leucadia’s agreement to purchase the Class A common stock was conditioned on, among other things, the Company (i) selecting a lead underwriter approved by Leucadia, (ii) having, together with its subsidiaries, no more than $295,000,000 of long-term debt outstanding (net of cash and cash equivalents), and (iii) the equity order book in such offering is no less than $40,000,000, excluding Leucadia’s commitment. On December 22, 2016 Leucadia purchased 3,478,261 shares of Class A common stock (costing $20,000,000) thus satisfying the Equity Backstop Commitment.

In connection with Leucadia’s commitment, the Company paid Leucadia on January 3, 2017 a $1,000,000 fee, which was recorded in accounts payable in the consolidated balance sheet at December 31, 2016. In the event Leucadia purchased not less than their commitment amount, the Company agreed to use commercially reasonable efforts to enter into arrangements to provide Leucadia with the right to appoint one director to the board of directors of the Company, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Class A common stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in such offering. Leucadia has elected to take an observer position on the board of directors, with no voting rights.

22

---

 

Purchase and Sale Agreement

On August 2, 2016, the Company entered into a purchase and sale agreement with Juneau, whereby we obtained an undivided 50% of Juneau’s interest in two producing wells and each well’s respective oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas. The total consideration was $5,500,000 payable in 500,227 shares of our Class A common stock.

 

Repurchase Facilitation Agreement

 

On October 26, 2016, effective September 29, 2016, the Company, by and on behalf of itself and certain of its subsidiaries, entered into an Amended and Restated Repurchase Facilitation Agreement (the “Amended and Restated Agreement”) with Seaport Global Securities LLC, a Delaware limited liability company (“Seaport Global”). Pursuant to the Amended and Restated Agreement, Seaport Global has agreed to provide the Company with financing (“Gap Financing”) from time to time in connection with the repurchase of the 8.750% Senior Notes, to be acquired by Seaport Global on the Company’s behalf in one or more open market purchases.

 

As of September 30, 2016, the Company recorded $2,063,320 as long-term debt on its balance sheet as a result of this financing. In December 2016, LRAI repaid the Gap Financing with proceeds from the 2016 Common Stock Offering.

2016 Common Stock Offering

 

On December 22, 2016, Lonestar Resources US Inc. issued 13.8 million shares of Class A common stock for approximately $79.4 million in gross proceeds. Lonestar applied a portion of the net proceeds from the offering to repurchase $21.0 million of its 12% Second Lien Notes at a price of 101% of par, while also repaying $49.0 million of its Senior Secured Credit Facility, and retiring the $2.1 million association with the Facilitation Agreement with Seaport Global.

 

Information Statement

On November 18, 2016, the board of directors of the Company unanimously approved and adopted, and recommended that the stockholders of the Company, as of November 22, 2016 (the “Record Date”), approve and adopt, the following actions:

On the Record Date, EFR Guernsey Holding Limited, the holder of a majority of the issued and outstanding shares of Class A common stock on that date, approved each of the foregoing actions (the “Actions”) by written consent, in lieu of a special meeting of the stockholders, to be effective at least 20 calendar days after the Information Statement (defined below) is sent to our stockholders.

The Company filed an information statement on Schedule 14C describing the Actions with the SEC and delivered the information statement describing the Actions (the “Information Statement”) to all stockholders of the Company as of the Record Date. The approval of the Actions was effective on December 22, 2016.

 

 

 

 

23

---

 

Item 1A. Risk Factors.

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, but are not limited to, the following:

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, 2016 was attributed to oil, our financial results are more sensitive to movements in oil prices.

As of December 31, 2016, we had in place hedges covering approximately 2,500 Bbls/d for 2017 at an average price of approximately $53.43 per Bbl. 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 $50.28 per bbl as of December 31, 2015, to $42.75 per bbl as of December 31, 2016 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 bbl in September 2014 to $52.01 per bbl at December 31, 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

24

---

 

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. In the event of further sustained declines, our liquidity could 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:

Furthermore, prolonged sustained further declines in oil, natural gas or NGL prices may reduce the amount of oil, natural gas and NGLs we can produce economically and negatively impact the value of our estimated oil, natural gas and NGL reserves, the carrying value of our oil, natural 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 cash flows and results of operations are highly dependent on our ability to find, develop or acquire additional oil and natural gas resources.

Our business strategy is to generate profit through the acquisition, exploration, development and production of crude oil and natural gas reserves. Our future success therefore depends on our ability to find, develop or acquire additional crude oil and natural gas reserves that are economically recoverable. 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.

Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Exploration and development activities involve numerous risks beyond our control, including the risk that no commercially productive oil or natural gas reservoirs will be discovered and that drilling will not result in commercially viable oil or natural gas production. In addition, the future cost and timing of drilling, completing and operating wells is often uncertain. Drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

Even if our exploitation, development and 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 impact our operations and financial position by reducing our available cash and liquidity. In addition, the potential for production decline rates for

25

---

 

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 $62 million and $72 million under our 2017 capital program to drilling and completing 13 gross (12 net) wells across our properties in the Eagle Ford Shale. We expect to fund our 2017 capital expenditures with cash generated by operations, our undrawn capacity under the Senior Secured Credit Facility and funding available under our Joint Development Agreement with IOG.

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 factors, including:

If our revenues or the borrowing base under the Senior Secured 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 the Senior Secured 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.

Any significant reduction in our borrowing base under the Senior Secured Credit Facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

The Senior Secured Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually on May 1 and November 1 of each year. The borrowing base depends on, among other things, our lenders’ evaluation of our oil and natural gas reserves. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the Senior Secured Credit Facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. Effective November 23, 2016, we received notification that the borrowing base for the Senior Secured Credit Facility was reduced to $112 million primarily as a result of the recent sale of our non-core legacy assets as described under Part I “Item I. Business—Overview—Non-Core Properties—Conventional Texas Assets.” Our next scheduled borrowing base redetermination is scheduled for May 1, 2017.

In the future, we may not have access to adequate funding under the Senior Secured Credit Facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of our lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover any defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or

26

---

 

otherwise carry out business plans or make required repayments under the Senior Secured Credit Facility, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

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

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

 

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, we are not insured against all operational risks and such coverage 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.

We could sustain significant losses and substantial liability 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 some of 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 some of 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:

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

27

---

 

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, it is more difficult 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 does not meet our anticipated results or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and limited takeaway capacity and/or declines in crude oil and natural gas prices, 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.

We may not adhere to our proposed drilling schedule.

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

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 statistical results of drilling activities in other 3-D project areas that we believe are geologically similar 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 those statistical results. In addition, our drilling schedule may vary from our expectations because of future uncertainties. In addition, our ability to produce oil and gas may be significantly affected by the availability and prices of hydraulic fracturing equipment and crews. There can be no assurance that these projects can be successfully developed or that any identified drill sites or budgeted wells will, if drilled, encounter reservoirs of commercially productive oil or gas. We may seek to sell or reduce all or a portion of our interest in a project area or with respect to prospects or budgeted wells within such project area.

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

SEC rules only permit, subject to limited exceptions, us to book our PUDs if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement 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 subject to many 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:

28

---

 

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 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 the addition of 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.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which the oil and gas industry has historically increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, and the costs for those items also increased. However, beginning in the second half of 2014, commodity prices began to decline and the demand for goods and services has subsided due to reduced activity. To the extent that commodity prices improve in the future, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to maintain or increase our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

Development of our estimated proved undeveloped reserves, or PUDs, may take longer than expected 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, 2016, approximately 76% of our total estimated proved reserves were classified as proved undeveloped reserves. 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 require us to reclassify our proved undeveloped reserves as unproved reserves.

29

---

 

Further, our reserves data assumes 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 and available capital.

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 93% of our production during the year ended December 31, 2016 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 70% 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 and result in a material adverse effect on our crude oil, natural gas and NGLs reserves and future production and, therefore, our future cash flow and income.

As of December 31, 2016, approximately 70% 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 and holding on to such leases.

 

Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage or we timely exercise our contractual rights to extend the terms of such leases by continuous operations or the payment of lease extension payments or delay rentals.

Leases on oil and natural gas properties typically have a primary term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established, applicable lease extension payments or delay rentals are made, or such lease is otherwise maintained pursuant to any applicable continuous operations provision. If our leases or term assignments on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. The primary term of the leases for a majority of our acreage that is not currently held by production will expire at the end of 2018 if such leases are not extended. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and productions costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. If commodity prices remain low, we may be required to delay our drilling plans and, as a result, may lose our right to develop the related properties.

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 actual quantities and present value of such 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 Annual Report on Form 10-K represents 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 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, revenues, 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 Annual Report on Form 10-K.

30

---

 

We depend upon several significant customers for the sale of most of our crude oil, natural gas and NGL production. The loss of one or more of these customers could adversely affect our revenues in the short term.

For the year ended December 31, 2016, purchases by our largest four customers accounted for 40%, 21%, 18% and 10%, 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.

Our hedging transactions expose us to counterparty credit risk.

Currently, all of our hedging arrangements are concentrated with three counterparties, each of which are lenders under the Senior Secured 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 for our crude oil, natural gas and NGLs.

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 Annual Report on Form 10-K is not necessarily the same as the current market value of our estimated crude oil and natural gas reserves. The current requirements for crude oil and natural gas reserve estimation and disclosures require the estimated discounted future net cash flows from proved reserves to be 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:

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.

We have incurred losses from operations for various periods since our inception and may continue to do so in the future.

We incurred a net loss of approximately $94.3 million for the year ended December 31, 2016. Our development of, and participation in, an increasingly larger number of prospects has required, and will continue to require, substantial capital expenditures. The uncertainty and factors described throughout this “Risk Factors” section may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to operate profitability and may not receive positive cash flows from operating activities in the future, which could adversely affect our business and the trading price of our Class A common stock.

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.

31

---

 

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.

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 facility. 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 facility and adversely impact our results of operations and liquidity 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 leases 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 firm transportation 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.

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 control over financial reporting and identify any material weaknesses in our internal control 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 annual report that addresses the effectiveness of our internal control 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. On November 21, 2016, our management identified a material weakness in the financial close process for the nine months ended September 30, 2016 relating to a failure to properly classify cash flows related to our gain on redemption of bonds, and concluded that

32

---

 

our internal control over financial reporting as September 30, 2016 was ineffective. In addition, in connection with the review of our unaudited condensed consolidated financial statements for the nine months ended September 30, 2015, management 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. Although these deficiencies have been remediated, 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 control over financial reporting, we will need to expend additional resources and provide additional 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 control 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 control 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 Class A 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.

The terms of the Senior Secured Credit Facility and the indenture that governs the Second Lien Notes may restrict our operations, particularly our ability to respond to changes or to take certain actions.

The indenture that governs the Notes and the Senior Secured Credit Facility contain a number of restrictive covenants that impose significant operating and financial restrictions 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:

In addition, the restrictive covenants in the Senior Secured 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 the Senior Secured 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 contained in the Notes and the Senior Secured Credit Facility, 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 further affect our ability to

33

---

 

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 current and future financing.

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

We intend to fund our capital expenditures in 2017 through cash flow from operations, from borrowings under the Senior Secured Credit Facility, 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 and we could face additional risks. Our level of debt could adversely affect our business and results of operations in several important ways, including the following:

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including the Senior Secured Credit Facility and senior notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flow and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness which would have a material adverse effect on our business and operations.

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.

The crude oil and natural gas industry is intensely competitive 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.

34

---

 

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

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:

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. If we are unable to achieve or manage growth, it 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 we do not have sufficient funds 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 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,

35

---

 

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 exploring for, and producing oil, natural gas and NGLs may expose our personnel and other third parties 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 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 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:

36

---

 

The Texas Railroad Commission recently adopted rules and regulations requiring that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well also must be disclosed to the public and filed with the Texas Railroad Commission. Any increased federal, state, local, foreign, or international regulation of hydraulic fracturing could reduce the volume of reserves that we can economically recover, which could materially and adversely affect our revenues and results of operations.

 

At the U.S. federal level, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. Also, in May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. To date, no other action has been taken. Further, the EPA finalized regulations under the CWA in June 2016 that prohibit wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that "water cycle" activities associated with hydraulic fracturing may impact drinking water resources "under some circumstances," noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In addition, the U.S. Department of the Interior finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.

There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts on surface water, and groundwater and, the potential for the disposal of produced water in underground formations to trigger earthquakes, and effects on the environment generally. A number of lawsuits and enforcement actions have been initiated across the country relating to hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Domenici-Barton Energy Policy Act of 2005 (“EP Act of 2005”), the Federal Energy Regulatory Commission (“FERC”) has civil penalty authority under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act (“NGPA”) to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

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.

37

---

 

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 in 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 due to drought conditions. 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. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations and cash flows.

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. For example, regulators in some states, including Texas, have responded to the potential concern that the injection of produced water (and other waste water from oil and gas operations) into underground disposal wells may trigger seismic activity.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage, use and discharge 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.

In connection with the EPA finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act (“CAA”) that, among other things, require reduced GHG emissions from certain large stationary sources, and the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. In May 2016, the EPA released final regulations intended to reduce methane emissions from the oil and gas industry, including throughout the natural gas supply chain. The 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. The EPA has also announced that it intends to propose similar standards for existing sources. The EPA also finalized rules in 2016 that clarify when crude oil and natural gas sites should be aggregated for purposes of air permitting, which could increase our compliance and permitting costs.

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. The U.S. is actively participating in international discussions that are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration. And in November 2014, President Obama announced that the U.S. would seek to cut net GHG emissions 26-28 percent below 2005 levels by 2025 in return for China’s commitment to seek to peak emissions around 2030, with concurrent increase in renewable energy. Most recently in December, the United States was one of 175 countries to adopt the Paris Agreement at the 21st Conference of Parties, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. On October 4, 2016, the E.U. ratified the Paris Agreement, thus meeting the threshold for the agreement to come into force. 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.

38

---

 

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.

Our systems and IT infrastructure may be subject to security breaches and other cyber security incidents.

We seek to maintain the security of computers, computer networks and data storage resources, as security breaches could result in vulnerabilities and loss of and/or unauthorized access to proprietary information and could negatively impact our business. We may face attempts by experienced hackers, cybercriminals or others with authorized access to our systems to misappropriate our proprietary information and technology, interrupt our business and/or gain unauthorized access to confidential information.

Our ability to use our net operating loss carryforwards may be limited.

As of December 31, 2016, we had approximately $58.1 million of U.S. federal net operating loss carryforwards (“NOLs”). Our NOLs begin to expire in 2030. Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of taxable income that may be offset by NOLs when a corporation has undergone an “ownership change” (as determined under Section 382). Generally, a change of more than 50% in the ownership of a corporation’s stock, by value, over a three-year period constitutes an ownership change for U.S. federal income tax purposes. Any unused annual limitation may be carried over to later years. We have previously experienced an ownership change and may experience more ownership changes in the future, which would result in an annual limitation under Section 382. The limitations arising from our prior ownership change or from any ownership change that may arise in the future may prevent utilization of our NOLs prior to their expiration. Future ownership changes or regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows if we attain profitability.

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 subject to changing and extensive tax laws, the effects of which cannot be predicted. In past years, legislation has been proposed in the Congress that, 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. These changes have included, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of crude oil and natural gas exploration and production companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available to us, and any such change could materially and adversely affect our business and financial condition.

39

---

 

These or any other similar changes in federal tax laws could defer or eliminate certain tax deductions that are currently available to us with respect to our 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, such changes 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 use to price our crude oil and natural gas sales 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 derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislation and any new regulations could:

40

---

 

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:

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 may not be 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 also involve other risks, including:

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.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Certain provisions in our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

41

---

 

In addition, we entered into a Board Representation Agreement (“Board Representation Agreement”) with EF Realisation pursuant to which it is entitled to nominate a number of directors so long as certain ownership thresholds are maintained. Please read Note 14. Related Party Activities—EF Realisation.

Our bylaws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

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 impact 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.

Item 1B. Unresolved Staff Comments.

None.

42

---

 

 

Item 2. Properties.

Information regarding our properties is included in Item 1. Business under “– Overview - Our Eagle Ford Shale Properties”, “–Non-Core Properties”, “–Oil and Natural Gas Data”, and “–Oil and Natural Gas Production Prices and Costs” above and in “Note 3. Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

In addition to the properties used in our operations, we lease office space in Fort Worth, Texas.

Item 3. Legal Proceedings.

From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position or results of operations.

Item 4. Mine Safety Disclosures.

Not applicable.

 

Executive Officers and Directors

The following table provides information regarding the Company’s executive officers and directors (ages are as of March 21, 2017):

Frank D. Bracken, III is our Chief Executive Officer. Mr. Bracken has served in this position since January 2012 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, acquisitions, 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.

43

---

 

Douglas W. Banister is our Chief Financial Officer. Mr. Banister has served in this position since January 2014 and previously served as Chief Accounting Officer of Lonestar Resources, Inc., our wholly-owned subsidiary since 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 Bachelor’s of Science in Mechanical Engineering with Highest Honors from the University of Texas in Austin.

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.

John Pinkerton has served as a Director since August 2014 and became Chairman of the Board in August 2016. He was a director of Range Resources Corporation (NYSE: RRC) since 1989 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 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. We believe that Mr. Pinkerton’s experience at oil and natural gas exploration companies qualify him for service on our board of directors.

Henry B. Ellis has served as a director since October 2016. Mr. Ellis presently serves as managing director and Chief Executive Officer of Bassett California Co. & The Bassett Company and previously served as a director of several other boards including Bluebonnet Savings Bank and State National Bank and served as President of Mbank, El Paso and Chairman and CEO of Grayson County Bank. Mr. Ellis received his Bachelor of Arts degree in Business Administration from Texas Christian University. We believe that Mr. Ellis’ financial experience in the banking industry qualifies him for service on our board of directors.

Bernard Lambilliotte has served as a director since January 2013. Mr. Lambilliotte served as Chief Investment Officer of Ecofin Limited, a specialist fund manager in equity, utilities and infrastructure, from 1992 until June 2016. 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 Hamon & Cie S.A., an international power engineering group based in Belgium, and also served as a director of Ecofin Water & Power Opportunities Plc from February 2002 to March 2014. 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. We believe that Mr. Lambilliotte’s background in investment banking and energy investing qualifies him to serve on our board of directors.

44

---

 

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. We believe that Mr. Lockwood’s engineering and management experience in the oil and gas industry qualifies him for service on our board of directors.

John H. Murray has served as a director since October 2016. Mr. Murray is Co-Founder, Executive Chairman and Chief Compliance Officer of Ecofin Limited, roles he has held since its incorporation in June 1991. Before founding Ecofin Limited, John headed the corporate finance department and was a member of the management committee of Swiss Bank Corporation’s London- based investment banking business. Prior to joining Swiss Bank Corporation, he worked for Morgan Stanley Group Inc. holding an office which he headed. John is a non-executive director of the Ecofin Vista Long/Short Fund Limited and the Ecofin Global Renewable Infrastructure Fund Limited and of the BlackRock Frontiers Investment Trust plc. John earned his BA in Economics from Williams College and an MBA from Harvard Business School. We believe that Mr. Murray’s financial experience in the investment banking industry qualifies him for service in our board of directors.

Stephen H. Oglesby has served as a director since March 2017. Before joining the company, Mr. Oglesby served as Head of Energy, US Commercial Bank at Citibank, where he managed multiple offices and oversaw financial services provided to various private and public companies in the oil and gas industry, from December 2003 to January 2017. Mr. Oglesby previously served on the board of directors of various private companies, including Advanced Coiled Tubing, where he served as Chairman of its board of directors, Blackwell Plastics, and Goodman Manufacturing. Mr. Oglesby holds a Bachelor of Science in Accounting from Southern Illinois University. We believe that Mr. Oglesby is qualified to serve on our board of directors because of his extensive experience in financial services for diversified corporate and energy clients, and his background in finance and accounting.

Dr. Christopher Rowland has served as a director of Lonestar since January 2013. He is also director of Special Situations for EF Realisation where he is responsible for initiating and monitoring and realizing investments. Prior to joining EF Realisation 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. We believe that Dr. Rowland’s academic background in economics and his professional experience in finance and energy investment qualify him to serve on our board of directors.

 

Randy L. Wolsey has served as a director since January 2017.  Mr. Wolsey is the founder and since February 2015 has been a co-owner of Lone Oak Minerals, a private company involved in the acquisition and selling of oil and gas minerals. Since January 2012, he has also been the owner of Solana, a private company involved in oil and gas and real estate investments. He is also the founder and since June 2006 has been a co-owner of Tanglewood Exploration, a private company involved in oil and gas exploration and production.  He previously held management positions at companies including Glen Rose Oil & Gas and Justin Exploration. Mr. Wolsey received his Bachelor of Arts degree in Political Science from Midwestern State University. We believe that Mr. Wolsey’s experience in the oil and gas industry qualifies him for service on our board of directors.

 

There are no family relationships among any of our directors or executive officers.

 

45

---

 

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our Class A common stock is listed on NASDAQ under the ticker symbol “LONE” and began trading on July 5, 2016 on the NASDAQ Global Select Market. The following table sets forth, for the periods indicated, the high and low sales prices per common share as reported on NASDAQ:

 

 

The closing market price of our common stock on March 17, 2017 was $5.89 per share. As of March 17, 2017, there were estimated 1,569 shareholders of record of our Class A common stock.

 

Dividend Policy

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 debt agreements, we are not permitted to pay cash dividends without the prior written consent of the lenders.

 

Use of Proceeds

On December 22, 2016, we completed our 2016 Common Stock Offering pursuant to a Registration Statement (File No. 333-214265), which was declared effective on December 15, 2016. Under the Registration Statement, on December 22, 2016, we sold 13,800,000 shares of our Class A common stock at a price of $5.75 per share, including, the 1,800,000 shares of our Class A common stock sold pursuant to the underwriters’ exercise of their option to purchase additional shares of our Class A common stock under the Registration Statement. Seaport Global Securities LLC as a managing underwriter and as representatives of the underwriters for the 2016 Common Stock Offering. The offering commenced on December 16, 2016 and did not terminate before all of the securities registered in the Registration Statement were sold. The Company raised from the 2016 Common Stock Offering net proceeds of approximately $71.8 million, after deducting total expenses of $6.6 million, including underwriting discounts and commissions of approximately $4.9 million and other expenses of $1.7 million. No offering expenses were paid or are payable, directly or indirectly, to any of our officers, directors or their associates, to any person owning 10% or more of any class of our equity securities or to any of our affiliates. No payments from the net proceeds were made, directly or indirectly, to any of our officers, directors, or their associates, to any person owning 10% or more of any class of our equity securities or to any of our affiliates. We used the net proceeds to repurchase $21.0 million of the Second Lien Notes at price of 101% par, repay $49.0 million of the Senior Secured Credit Facility, and retire the $2.1 million Repurchase Facilitation Agreement with Seaport Global, with the remaining proceeds used for general corporate purposes. There has been no material change in the use of proceeds as described in our prospectus, dated December 16, 2016, filed with the Securities and Exchange Commission (“SEC”) in accordance with Rule 424(b) of the Securities Act of 1933, as amended, on December 20, 2016.

 

Repurchase of Equity Securities

None.

Item 6. Selected Financial Data.

On July 5, 2016, Lonestar Resources US Inc. (the “Successor”) acquired all of the issued and outstanding ordinary shares of Lonestar Resources Limited (the “Predecessor”) pursuant to a Scheme of Arrangement under Australian law (the “Reorganization”). The following table presents selected historical consolidated financial data of the Successor and the Predecessor, as applicable, as of the dates and for the periods indicated. The selected historical consolidated financial data as of and for the years ended December 31, 2016 and 2015 are derived from the audited financial statements appearing elsewhere in this Annual Report on Form 10-K. The

46

---

 

selected historical consolidated financial data as of, and for the year ended, December 31, 2014 are derived from the audited financial statements not included herein. Historical results are not necessarily indicative of future results.

The selected historical consolidated financial data presented below should be read in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes and other financial data included elsewhere in this Annual Report on Form 10-K.

47

---

 

 

 

 

 

48

---

 

Summary Historical Reserve and Operating Data

The following table presents estimated net proved oil, NGLs and natural gas reserves attributable to our properties and the Standardized Measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2016, 2015 and 2014. We employ a technical staff of engineers and geoscientists that perform technical analysis of each producing well and undeveloped location. The staff uses industry accepted practices to estimate, with reasonable certainty, the economically producible oil and gas reserves. The practices for estimating hydrocarbons in place include, but are not limited to, mapping, seismic interpretation, core analysis, log analysis, mechanical properties of formations, thermal maturity, well testing and flowing bottom hole pressure analysis. We employ an independent petroleum engineer to estimate 100% of our proved reserves. The data below is based on our reserve report prepared by W.D. Von Gonten & Co. for our Eagle Ford Shale properties and on the reserve report prepared by LaRoche Petroleum Consultants, Ltd. for our conventional properties in the State of Texas. The Standardized Measure and PV-10 amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves. Therefore, those reserves are not included in the table below. 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.

 

49

---

 

 

We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date. NYMEX futures prices are not necessarily a projection of future oil and natural gas prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil and natural gas reserves.

The data in the table above represent estimates only. Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure amounts shown above should not be construed as the current market value of our estimated oil, NGLs and natural gas reserves. The 10% discount factor used to calculate Standardized Measure, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

 

50

---

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the related notes and other financial information included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Important factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

General Overview

We are an independent oil and natural gas company, focused on the development, production and acquisition of unconventional oil, natural gas liquids (“NGLs”) and natural gas properties in the Eagle Ford Shale in Texas, where we have accumulated approximately 41,274 gross (34,170 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of December 31, 2016. As of December 31, 2016, we also hold and are conducting resource evaluation on approximately 44,084 gross (28,655 net) acres in the West Poplar area in Roosevelt County, Montana. 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 United States, and, as of December 31, 2016, we had no long lived assets located outside the United States.

Operational Results Total production for the year ended December 31, 2016 decreased 8% from 2015 to 5,899 Boe/d, primarily due to the sale of the divestiture of all conventional assets in the second half of 2016 and the fact that Lonestar did not place any new Eagle Ford Shale wells onstream during the third or fourth quarters of 2016, as the Company chose to focus its spending on debt reduction.

See the table below for details of our drilling and completion activity:

 

In 2016, 100% of our drilling and completion capital expenditures was related to the Eagle Ford Shale where, as of December 31, 2016, we were operating one rig. At December 31, 2016, our estimated net proved oil and gas reserves across all of our properties were 40.5 MMBoe, an increase of 0.3 MMBoe, or 1%, from December 31, 2015. Driven by our drilling program as well as the associated offset locations, we added 2.5 MMBoe to our total proved reserves in the Eagle Ford Shale. Due to the sales of our conventional assets in 2016, proved reserves decreased by 2.1 MMBoe. See “Item 1. Business—Oil and Natural Gas Data—Estimated Proved Reserves” for additional discussion.

 

Our current 2017 capital expenditure plan includes $62.0 million to $72.0 million for drilling and completion and $10 million for leasehold acquisition expenditures. We have historically grown our Eagle Ford leasehold position through acquisitions, organic leasing activities, farm-ins and other structures. We believe our management team’s extensive experience in the basin provides us with relationships and contacts that could serve as a platform for expanded opportunities to grow our acreage footprint.

 

Acquisition Activity. On August 2, 2016, the Company entered into a purchase and sale agreement with Juneau Energy, LLC, whereby we obtained an undivided 50% of Juneau’s interest in two producing wells and each well’s respective oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas. The total consideration was $5,500,000 payable in 500,227 shares of our Class A common stock.

 

51

---

 

2016 Common Stock Offering. On December 22, 2016, Lonestar Resources US Inc. issued 13.8 million shares of Class A common stock for approximately $79.4 million in gross proceeds. Lonestar applied a portion of the net proceeds from the offering to repurchase $21.0 million of its 12% Second Lien Notes at a price of 101% of par, while also repaying $49.0 million of the Senior Secured Credit Facility, and retiring the $2.1 million Repurchase Facilitation Agreement with Seaport Global.

 

Senior Secured Credit Facility. Effective November 23, 2016, LRAI received notification that the borrowing base was reduced from $120 million to $112 million, principally as a result of the sale of our conventional assets during the second half of 2016. See “Note 10. Long-Term Debt” of the Notes to our Consolidated Financial Statements for further details.

Second Lien Notes. During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued warrants to purchase 760,000 shares of its Class A common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value of the warrants at the date of issuance.  The warrants were adjusted to fair value at December 31, 2016 which resulted in an unrealized gain on warrants of approximately $0.6 million. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million. In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering.

 

Financial Results. We recorded a loss for the years ended December 31, 2016 and 2015 of $94.3 million, or $11.64 per diluted share, and $27.3 million, or $3.63 per diluted share, respectively. The loss for the year ended December 31, 2016 was driven by a $33.9 million impairment charge and $36.4 million of non-cash unrealized hedging losses on derivatives which were partially offset by a $28.5 million gain on bond disposal. The loss from continuing operations for the year ended 2015 was driven by impairments of proved oil and gas properties of $28.6 million as a result of declines in the 12-Month average realized prices of crude oil.

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 year ended December 31, 2016 compared to the year ended December 31, 2015

Net Production

 

 

Production volumes in 2016 were 5,899 Boe/d, a decrease of 8% from 6,408 Boe/d in 2015. The decrease in our average daily production is a result of 1) the divestiture of all Conventional assets in October, 2016 and 2) not bringing any additional wells online

52

---

 

since the 3 months ended June 30, 2016. For the year ended December 31, 2016, approximately 55% of our production was crude oil, 20% was NGLs and 25% was natural gas.     

Average Sales Price

 

 

The average wellhead price for our production in 2016 was $26.85 per Boe, which was 21% lower than the average price in 2015. Reported wellhead realizations were driven lower by a decline (approximately 11%) in WTI pricing between the periods. While the benchmark price fell sharply, our crude oil hedge positions added $23.25 per barrel of oil to our realizations or $12.83 per barrel of oil equivalent.

53

---

 

Revenues

 

 

Wellhead revenue in 2016 was $58.0 million, a 27% decrease from $79.5 million in 2015. Due to the significant decrease in benchmark prices, we realized favorable crude oil hedge cash settlements, which added $27.7 million in gains on commodity derivatives for the year ended December 31, 2016.

Costs and Expenses

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

 

Lease Operating and Gas Gathering 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.

54

---

 

Our total lease operating expenses in 2016 were $16.2 million, a decrease of 6% from $17.2 million in 2015. This decrease was largely due to an 8% decrease in production.  On a unit-of-production basis, our lease operating expenses in 2016 was $7.52 per Boe, an increase of 2% from $7.35 per Boe in 2015.

Production, 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, severance, and ad valorem taxes in 2016 were $3.3 million, a 34% decrease from $5.0 million in 2015. The decrease was principally due to the 27% decline in wellhead revenues.

Rig Standby Expense

During the year ended December 31, 2016, we incurred rig standby expense of $2.3 million related to the drilling rig we had under contract.

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 unit-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 in 2016 was $47.1 million, a 20% decrease from $59 million in 2015 primarily due to an 8% decrease in production in 2016.

 

Impairment of Oil and Gas Properties 

During 2016, certain leased acreage expired in the Bakken, Three Forks, and Lower Lodgepole formations (collectively, the “Poplar Properties”). Based on our decision to defer drilling on the Poplar Properties, the Company recorded an approximate $1.9 million impairment charge related to the leased acreage expiring during 2016. This was calculated through the allocation of our current carrying value of the properties across our proportionate share of the acreage. The Company is currently evaluating its 2017 capital budget for this area.  The Poplar Properties leasehold that may expire in 2017 are not expected to impair the Company’s ability to initiate drilling activity. Certain leased acreage in Wilson County, Texas expired in October 2016.  The Company decided to not extend the leases tied to this acreage, and therefore, the leasehold costs associated with this acreage were impaired as a result of these lease expirations, and as a result, the Company recorded an impairment charge of approximately $2.8 million.  At September 30, 2016, we recorded impairment of approximately $29.1 million related to our conventional assets representing carrying value in excess of fair value, less the cost to sell the properties.  These assets were subsequently sold, and the transaction closed on October 31, 2016.

If pricing continues to decline, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to December 31, 2016. 

55

---

 

General and Administrative (G&A) Expenses

G&A expense in 2016 was $11.3 million, a 5% increase from $10.8 million in 2015, primarily as a result of approximately $1.5 million of legal and audit expenses in 2016 associated with the Company’s efforts to re-domicile to the United States and to list on the NASDAQ Global Select Market.

Interest Expense

Our interest expense in 2016 was $29.6, an increase of 20% from $24.6 in 2015 due primarily to an increase in bond discount interest and warrant discount interest associated with warrants issued with the Second Lien Notes.

 

Gains (Losses) on Derivative Financial Instruments

In the year ended December 31, 2016, we recognized a non-cash $36.4 million loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $27.7 million realized gain on settlement of our commodity derivative contracts. In the year ended December 31, 2015, we recognized a non-cash $8.7 million unrealized 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 derivatives contracts. Settlement of the crude oil hedge positions in 2016 added $23.25 per barrel to crude oil price realization compared to $23.54 in 2015.

Income Taxes

As a result of the net loss before income tax of $66.9 million in the year ended December 31, 2016 and net loss before income tax of $42.5 million from the year ended December 31, 2015, we recorded income tax expense of $27.4 million and an income tax benefit of $15.1 million in the year ended December 31, 2016 and 2015, respectively.  On December 22, 2016, the Company completed a public offering of 13.8 million of its Class A common stock, creating a change of ownership as defined under the provisions of Section 382 of the Internal Revenue Code at that date.  As a result of this ownership change, certain of our accumulated net operating losses will be subject to an annual limitation regarding their utilization against taxable income in future periods.   Due to the ownership change and the resulting limitation on the utilization of net operating loss generated prior to the change, an estimated $141.7 million of the net operating loss carryforwards have been written off in 2016.  The tax effect of this limitation is included in the income tax expense amount recorded as of December 31, 2016.     

Net Income (Loss) Before Taxes

As a result of the above factors, and particularly the $21.5 million decrease (-27% ) in revenue resulting from the decline in crude oil and natural gas benchmark prices, we recorded a net loss before income tax of $66.9 million in the year ended December 31, 2016 compared to net loss before income tax of $42.5 million in the year ended December 31, 2015.

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 $500,000,000 Senior Secured Credit Facility (the “Senior Secured Credit Facility”).

We have historically financed our acquisition and development activity through cash flows generated by operating activities, borrowings under our Senior Secured Credit Facility, and the issuance of bonds.

On August 2, 2016, the Company entered into a purchase and sale agreement with Juneau, whereby we obtained an undivided 50% of Juneau’s interest in two producing wells and each well’s respective oil and gas leases covering approximately 1,300 net

56

---

 

mineral acres located in Brazos County, Texas. The total purchase was $5,500,000 payable in 500,227 shares of our Class A common stock. 

At December 31, 2016, we had $6.1 million in cash and cash equivalents and approximately $68.2 million of additional availability under our Senior Secured Credit Facility.  We believe that our existing cash and cash equivalents, cash expected to be generated from operations and the availability of borrowing under our Senior Secured Credit Facility will be sufficient to meet our liquidity requirements, operating expenses, anticipated capital expenditures and payments due under our existing credit facility and notes outstanding for at least the next 12 months.

Senior Secured Credit Facility

On July 28, 2015, LRAI entered into a Credit Agreement (as amended, supplemented and modified, the “Credit Agreement”) in connection with a new $500,000,000 Senior Secured Credit Facility (the “Senior Secured Credit Facility”) which replaced a $400,000,000 Wells Fargo-led syndicated facility. The new facility was arranged by Citibank, N.A. and featured 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. Effective as of May 19, 2016, the borrowing base was reduced from $180,000,000 to $120,000,000.

As of December 31, 2016 (giving effect to the amended covenant ratio discussed below), LRAI was in compliance with all covenants including all financial ratios under Credit Agreement. As of December 31, 2016, $43,500,000 was borrowed under the Senior Secured Credit Facility.

The Senior Secured Credit Facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. The Senior Secured Credit Facility provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the Senior Secured Credit Facility.

Borrowings under the Senior Secured Credit Facility, at LRAI’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) 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. In connection with the Senior Secured Credit Facility, LRAI and certain of its subsidiaries also entered into certain customary ancillary agreements and arrangements, which, among other things, provide that the indebtedness, obligations, and liabilities of the Company arising under or in connection with the Senior Secured Credit Facility are unconditionally guaranteed by such subsidiaries.

Effective as of July 27, 2016, LRAI, the several banks and other financial institutions party thereto (collectively, the “Consenting Lenders”) and Citibank, N.A., in its capacity as administrative agent for the lenders (the “Administrative Agent”) entered into the Third Amendment to Credit Agreement and Limited Waiver (the “Amendment”) to the Credit Agreement  to (a) permit LRAI to incur the second lien obligations contemplated by the Securities Purchase Agreement with Leucadia National Corporation and others (as described below) and LRAI’s contemplated use of proceeds thereof, (b) increase the applicable margin for Eurodollar and ABR loans and letter of credit fees by 0.75% across all levels of the previously applicable pricing grid, (c) modify the fee payable on the actual daily unused amount of the aggregate commitments to a flat 0.50% across all levels of the pricing grid, (d) increase the minimum percentage of the value of LRAI’s oil and gas properties that must be mortgaged as collateral for the obligations under the Credit Agreement and the other loan documents from 80% to 90%, (e) modify the maximum leverage ratio thresholds from 4.0 to 1.0 to (i) 4.75 to 1.0 for the four quarterly periods ending June 30, 2016, (ii) 4.50 to 1.0 for the four quarterly periods ending September 30, 2016, (iii) 4.25 to 1.0 for the four quarterly periods ending December 31, 2016 and (iv) 4.00 to 1.0 for all periods thereafter, (f) prohibit distributions to the Predecessor for general and administrative expenses after September 30, 2016 and (g) amend certain other provisions of the Credit Agreement as more specifically set forth in the Amendment.

Securities Purchase Agreement and Second Lien Notes

On August 2, 2016, LRAI and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC, as initial purchaser (the “Initial Purchaser”), Leucadia National Corporation (“Leucadia”), as guarantor of the Initial Purchaser’s obligations, the other purchasers party thereto (collectively, along with the Initial Purchaser, the “Purchasers”) and Jefferies, LLC, in its capacity as the collateral agent for the Purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share

57

---

 

(the “Warrants” and, together with the Second Lien Notes, the “Securities”). The balance of these notes and warrants is reflected in our long-term debt – related parties and equity warrant liability – related parties on the face of the balance sheet.

The Second Lien Notes are secured by second-priority liens on substantially all of LRAI’s and its subsidiaries’ assets to the extent such assets secure obligations under the Senior Secured Credit Facility.

During 2016, the LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 760,000 shares of the company’s Class A common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance.  The warrants were adjusted to fair value at December 31, 2016 which resulted in an unrealized gain on warrants of approximately $0.6 million. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes  in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.  

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering, reducing the outstanding amount to $17.0 million as of December 31, 2016.

2016 Common Stock Offering

On December 22, 2016, the Company issued 13.8 million shares of Class A common stock for approximately $79.4 million in gross proceeds. The Company applied a portion of the net proceeds from the offering to repurchase $21.0 million of its 12% Second Lien Notes at a price of 101% of par, while also repaying $49.0 million of the Senior Secured Credit Facility, and retiring the $2.1 million Repurchase Facilitation Agreement with Seaport Global.

 

Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled ($15.9) million and $14.5 million as of December 31, 2016 and December 31, 2015, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $6.1 million and $4.3 million as of December 31, 2016 and December 31, 2015, respectively. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our credit agreement will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

Historical Cash Flows

The following table summarizes our cash flows for the periods indicated, as shown on the consolidated statements of cash flows:

 

 

Net Cash Provided By Operating Activities

Net cash provided by operating activities decreased $26.6 million from $50.8 million in the year ended December 31, 2015 to $24.3 million in the year ended December 31, 2016. This decrease is primarily due to a $67.0 million increase in net loss, a $28.5 million gain on redemption of bonds, an $11.9 million decrease in depreciation, depletion and amortization, a $5.5 million decrease in derivative settlements, and a $2.1 million decrease in stock-based compensation, offset by a $36.3 million increase in loss on derivative financial instruments, $42.6 million increase in deferred taxes, a $6.5 million increase in non-cash interest expense, and an increase in impairment charges of $5.3 million during the year ended December 31, 2016.

58

---

 

Net Cash Used In Investing Activities

Net cash used in investing activities decreased $66.7 million from $94.5 million in the year ended December 31, 2015 to $27.8 million in the year ended December 31, 2016. This decrease is primarily due to a $4.4 million decrease in the acquisition of oil and gas properties, a $46.1 million decrease in the development of oil and gas properties, offset by $16.2 million in proceeds from sales of oil and gas properties in the year ended December 31, 2016.

Net Cash Provided By Financing Activities

Net cash provided by financing activities decreased $32.7 million from $38.0 million provided during the year ended December 31, 2015 to $5.3 million provided in the year ended December 31, 2016. This decrease was due to decreased bank borrowings of $68.4 million and increased payments on borrowings of $32.2 million, offset by net proceeds of $72.8 million from the issuance of Class A common stock in the year ended December 31, 2016.

Hedging

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

 

 

The above derivative contracts aggregate to 912,600 barrels or 2,500 barrels of oil per day for 2017 and 730,000 barrels or 2,000 barrels of oil per day for 2018. Our 2017 derivative contracts consist of 1,500 Bbls/day swaps at a volume weighted average price of $52.22 and three-way collars covering 1,000 Bbls/d, which provide an effective floor of $55.25 per Bbl with WTI prices between $40.00 per Bbl and $60.00 per Bbl, and also gives upside to $80.25 per Bbl. Our 2018 derivative contracts consist of 1,500 Bbls/day swaps at a volume weighted average price of $54.67 and two- way collars covering 500 Bbls/day with a price ceiling of $59.45.

In January 2017, we entered into additional WTI crude oil swaps covering a total of 137,500 barrels for the period of April 2017 through December 2017 at an average strike price of $56.00. The addition of these swaps increased our total 2017 crude oil hedge position coverage to a total of approximately 2,877 barrels of oil per day at an average strike price of $53.77 per barrel. Also in January 2017, we entered into WTI crude oil swaps covering a total of 182,500 barrels for the period of January 2018 through December 2018 at an average strike price of $55.50. These additional 2018 swaps increased our total 2018 crude oil hedge position coverage to a total of approximately 2,500 barrels of oil per day at an average strike price of $55.33.

The above natural gas derivative contract equates to 7,000 MMBtu per day for 2017.

Indebtedness

As of December 31, 2016, we had an aggregate of $207.5 million of indebtedness, including $43.5 million drawn on our Senior Secured Credit Facility, $17.0 million (less debt issuance costs of $0.3 million and unamortized discounts of $2.2 million) on our Second Lien Notes, $151.8 million (less an unamortized discount of  $1.7 million and debt issuance costs of $0.9 million) on our 8.750% Senior Notes and $0.3 million of other long-term notes.

Senior Secured Credit Facility

As of December 31, 2016, LRAI had outstanding borrowings of approximately $43.5 million under the Senior Secured Credit Facility, which was subject to an average interest rate of approximately 4.11% and 3.39% during the three months and year ended

59

---

 

December 31, 2016, respectively. Additionally, the Senior Secured Credit Facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. LRAI has $300,000 of advances on the letter of credit as of December 31, 2016. The borrowing base under the Senior Secured 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 November 23, 2016, LRAI received notification that the borrowing base was reduced to $112 million, principally as a result of the sale of our conventional assets during the second half of 2016. 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 May 1, 2017.

8.750% Senior Notes

LRAI issued $220 million aggregate principal amount of the 8.750% Senior Notes in April 2014 under an indenture among LRAI, its subsidiary guarantors and Wells Fargo Bank, National Association, as trustee.  The Company is not a party to the indenture.

The 8.750% Senior 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 8.750% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each subsidiary of LRAI.

During 2016, the Company repurchased $68.2 million in aggregate principal amount of the 8.750% Senior Notes resulting in approximately $28.5 million gain on disposal, bringing the balance to $151.8 million as of December 31, 2016.

Securities Purchase Agreement and Second Lien Notes

On August 2, 2016, LRAI and the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC, as initial purchaser (the “Initial Purchaser”), Leucadia National Corporation (“Leucadia”), as guarantor of the Initial Purchaser’s obligations, the other purchasers party thereto (collectively, along with the Initial Purchaser, the “Purchasers”) and Jefferies, LLC, in its capacity as the collateral agent for the Purchasers, relating to the issuance and sale of (i) up to $49.9 million aggregate principal amount of the Second Lien Notes and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share.

During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 760,000 shares of its Class A common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance.  The warrants were adjusted to fair value at December 31, 2016 which resulted in an unrealized gain on warrants of approximately $0.6 million. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes  in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering, bringing the balance to $17.0 million as of December 31, 2016.

Capital Expenditures

Historical capital expenditures

The table below summarizes our capital expenditures incurred for the year ended December 31, 2016 . We plan to invest the majority of our 2017 capital budget for the horizontal development of our Eagle Ford Shale properties and have allocated between $62 million and $72 million to drilling and completion activities to develop these assets, of which up to $10 million is allocated for leasehold acquisition expenditures.

 

60

---

 

Critical Accounting Policies and 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. The 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 are described below. As of December 31, 2016, there were no significant changes to any of our critical accounting policies and estimates.

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, 2016 would have decreased or increased our DD&A expense of proved oil and gas properties by approximately $3.8 million or 9% or $4.6 million or 10%, respectively, for the year ended December 31, 2016.

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

61

---

 

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 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.

62

---

 

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 a 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.

Recently Issued Accounting Pronouncements

See “Note 2. Recently Issued Accounting Pronouncements” of the Notes to Consolidated Financial Statements for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards Board.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2016 or 2015. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

 

 

Item 7A. Quantitative and Qualitative Disclosures About Market 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, Senior Secured Credit Facility, bonds 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.

Commodity Price Risk

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

63

---

 

cartels and global economic and political developments. The following table shows the fair value of our derivative contracts and the hypothetical result from a 10% change in commodity prices at December 31, 2016. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks could be mitigated by price changes in the underlying physical commodity (in thousands):

Our board of directors reviews oil and natural gas hedging on a quarterly 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 three counterparties, each of which are lenders under the Senior Secured 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.

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

 

 

 

The above derivative contracts aggregate to 912,600 barrels or 2,500 barrels of oil per day for 2017 and 730,000 barrels or 2,000 barrels of oil per day for 2018. Our 2017 derivative contracts consists of 1,500 Bbls/day swaps at a volume weighted average price of $52.22 and three-way collars covering 1,000 Bbls/d, which provide an effective floor of $55.25 per barrel with WTI prices between $40.00 per Bbl and $60.00 per Bbl, and also gives upside to $80.25 per Bbl. Our 2018 derivative contracts consist of 1,500 Bbls/day swaps at a volume weighted average price of $54.67 and two- way collars covering 500 Bbls/day with a price ceiling of $59.45.

In January 2017, we entered into additional WTI crude oil swaps covering a total of 137,500 barrels for the period of April 2017 through December 2017 at an average strike price of $56.00 per barrel. The addition of these swaps increased our total 2017 crude oil hedge position coverage to a total of approximately 2,877 barrels of oil per day at an average strike price of $53.77 per barrel. Also in January 2017, we entered into WTI crude oil swaps covering a total of 182,500 barrels for the period of January 2018 through December 2018 at an average strike price of $55.50 per barrel. These additional 2018 swaps increased our total 2018 crude oil hedge position coverage to a total of approximately 2,500 barrels of oil per day at an average strike price of $55.33 per barrel.

64

---

 

The above natural gas derivative contract equates to 7,000 MMBtu per day for 2017.

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 Senior Secured Credit Facility 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.

Interest Rate Risk

As of December 31, 2016, we had $43.5 million outstanding under the Senior Secured Credit Facility, which is subject to floating market rates of interest. Borrowings under the Senior Secured 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, 2016, a 100 basis point change in interest rates would change our annualized interest expense by approximately $0.44 million.

Item 8. Financial Statements and Supplementary Data.

The financial statements and supplementary information required by this Item appears on pages F-1 through F-28 of this Annual Report on Form 10-K.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.  In addition, the design of disclosure controls and procedures must reflect the fact that there are resources constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Evaluation of Disclosures Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated, as of the end of the period covered by this Annual Report on Form 10-K, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended). As previously disclosed and further described below, we identified a material weakness in our internal control over financial reporting. As a result of the subsequent remediation of this material weakness described below and based on the foregoing evaluation by our management, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2016.

Management’s Annual Report on Internal Control Over Financial Reporting

This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.

Remediation of Material Weakness

As previously disclosed in our Amendment No. 1 (the “10-Q Amendment”) to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 (“Original Filing”), filed with the SEC on November 10, 2016, during the fourth quarter of 2016,

65

---

 

our management determined that a material weakness existed in the Company’s internal control over financial reporting, specifically over reporting of cash flows. Management identified certain noncash errors in our unaudited consolidated statement of cash flows for the nine months ended September 30, 2016 due to an error in the proper classification of cash flows related to our gain on redemption of bonds. This material weakness resulted in the restatement of our unaudited consolidated financial statements as of and for the nine months ended September 30, 2016 as described in the 10-Q Amendment.

To remediate the material weakness described above and enhance our internal control over financial reporting, management (i) instituted a financial reporting issues log to record and track infrequent and unusual financial transactions (as was the gain on redemption of bonds) as a means to promote discussion between management and third party professional consultants to ensure that all items are addressed correctly and timely in future financial reporting, and (ii) enhanced the Company’s formal monthly and quarterly close procedures, implemented beginning with the month and quarter ended December 31, 2016, to ensure (a) adequate accounting consideration and review of the completeness of the significant, unusual transaction checklist occurs each period and (b) both a general and detail review of the Company's financial statements and related footnotes occurs each period. As a result of the implementation of these controls, management has determined that the foregoing material weakness has been remediated.

Changes in Internal Controls

There was no change in our internal control over financial reporting, other than the remediation measures described above, during the quarter ended December 31, 2016 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

66

---

 

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors, and employees, which is available on our website at www.lonestarresources.com in the “Shareholder Information” section under “Governance.” We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our Code of Business Conduct and Ethics, as well as NASDAQ’s requirements to disclose waivers with respect to directors and executive officer, by posting such information on our website at the address and location specified above.

The information concerning our executive officers and directors in response to this item is contained above in part under the caption “Executive Officers and Directors” at the end of Part I of this Annual Report on Form 10-K.  The remainder of the response to this item is contained in the Proxy Statement for our 2017 Annual Meeting of Stockholders and is incorporated herein by reference.

Item 11. Executive Compensation.

The information required by this item will be included in our Proxy Statement for our 2017 Annual Meeting of Stockholders, and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item will be included in our Proxy Statement for our 2017 Annual Meeting of Stockholders, and is incorporated herein by reference.  

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by this item will be included in our Proxy Statement for our 2017 Annual Meeting of Stockholders, and is incorporated herein by reference.  

Item 14. Principal Accounting Fees and Services.

The information required by this item will be included in our Proxy Statement for our 2017 Annual Meeting of Stockholders, and is incorporated herein by reference.

67

---

 

PART IV

Item 15. Exhibits, Financial Statement Schedules.

See the “Index to Consolidated Financial Statements on page F-1 below for the list of financial statements filed as part of this report.

All schedules have been omitted because they are not required or because the required information is given in the Consolidated Financial Statements or Notes thereto set forth below beginning on page F-1.

See the Exhibit Index immediately following the signature of this Annual Report on Form 10-K.  The exhibits listed in the Exhibit Index below are filed or incorporated by reference as part of this Annual Report on Form 10-K.

Item 16. Form 10-K Summary

None.

 

68

---

 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.

 

 

 

69

---

 

Exhibit Index

70

---

 

 

 

 

 

 

71

---

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

F-1

---

 

Report of Independent Registered Public Accounting Firm

 

Board of Directors and Shareholders

Lonestar Resources US Inc.

Fort Worth, Texas

We have audited the accompanying consolidated balance sheets of Lonestar Resources US Inc. and Subsidiaries (the Company) as of December 31, 2016 and 2015, and the related consolidated statements of operations and other comprehensive loss, changes in stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Lonestar Resources US Inc. and Subsidiaries at December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Dallas, Texas

March 23, 2017

 

F-2

---

 

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

Lonestar Resources US Inc.

Consolidated Balance Sheets

(In thousands, except share and per share data)

 

 

See accompanying notes to consolidated financial statements.

F-3

---

 

Lonestar Resources US Inc.

Consolidated Balance Sheets (continued)

(In thousands, except share and per share data)

 

 

See accompanying notes to consolidated financial statements.

 

 

F-4

---

 

Lonestar Resources US Inc.

Consolidated Statements of Operations & Comprehensive Loss

(In thousands, except share and per share data)

 

 

 

See accompanying notes to consolidated financial statements.

F-5

---

 

Lonestar Resources US Inc.

Consolidated Statements of Changes in Stockholders’ Equity

(In thousands, except share data)

 

 

 

See accompanying notes to consolidated financial statements.

 

 

F-6

---

 

Lonestar Resources US Inc.

Consolidated Statements of Cash Flows

(In thousands)

 

 

 

See accompanying notes to consolidated financial statements.

 

F-7

---

 

Lonestar Resources US Inc.

Notes to Consolidated Financial Statements

 

1. Nature of Business and Presentation

Lonestar Resources US Inc. (the “Successor”) was incorporated in Delaware in December 2015 for purposes of effecting our corporate reorganization, which was completed on July 5, 2016 (the “Reorganization”), pursuant to a Scheme Implementation Agreement (the “Scheme”), dated December 28, 2015, between the Successor and Lonestar Resources Limited (the “Predecessor”), an Australian company. Prior to the Reorganization, our business was owned and operated under our Predecessor, whose ordinary shares were listed on the Australian Securities Exchange (“ASX”). Pursuant to the Scheme, the Successor acquired all of the issued and outstanding ordinary shares of our Predecessor, and each of our Predecessor’s shareholders received one share of our Class A voting common stock (“Class A common stock”) for every two ordinary shares of our Predecessor such shareholder held. Prior to the Reorganization, the Successor had no business or operations, and following the Reorganization, the business and the operations of the Successor consist solely of the business and operations of the subsidiaries of the Predecessor.  The reorganization was treated as a transaction among parties under common control and no gain or loss was recorded.  

Lonestar Resources America, Inc. (“LRAI”) is a Delaware registered U.S. holding company formed on 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, Lonestar Resources, Inc. and Amadeus Petroleum, Inc. Its executive offices are located in Fort Worth, Texas. LRAI was a wholly owned subsidiary of the Predecessor, prior to the reorganization described below.  The majority of the activities of the Predecessor was carried out through LRAI. Unless the context otherwise requires, references to “Lonestar,” “we,” “us,” “our,” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable.

Basis of Accounting

The accounts are maintained and the consolidated financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect certain reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from these estimates and assumptions.

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.

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”),

Lonestar Resources Intermediate, Inc. (“LRII”)

LNR America, Inc. (“LNRA”),

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”),

F-8

---

 

Eagleford Gas 9, LLC (“Eagleford Gas 9”)

Lonestar Operating, LLC (“LNO”),

Lonestar BR Disposal, LLC (“LBRD”)

La Salle Eagle Ford Gathering Line, LLC (“LSGL”)

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.

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 material credit losses since its inception, however, an allowance for uncollectible amounts of approximately $196,000 was recorded at December 31, 2016, relating to receivables from joint interest owners of our conventional properties that were sold in the second half of 2016.

Oil, NGL and natural gas revenues from Shell Trading (US) Company, Texla Energy Management, Inc., Trafigura AG, and BP Products North America LLC for the year ended December 31, 2016, represented 40%, 21%, 18% and 10%, respectively, of total revenues.  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. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and Texla Energy Management, Inc. represented 49%, 30% and 13%, respectively, of total receivables at December 31, 2016. 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. 

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.

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

F-9

---

 

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.

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.

 

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 sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the 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 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. As a result of this evaluation, the Company recorded impairment of unproved oil and gas properties of approximately $4.8 million and $8.9 million for the years ended December 31, 2016 and 2015, respectively, and impairment of proven oil and gas properties of $29.1 million and $19.7 million for the years ended December 31, 2016 and 2015, respectively.  If pricing declines, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to December 31, 2016.

Asset Retirement Obligations

The Company accounts 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. See Note 8.

Revenue Recognition

Oil, NGL and natural gas revenues are recognized when title to the product transfers to the purchaser. The Company follows the sales method of accounting for its crude oil, NGL and natural gas revenue, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no imbalances at December 31, 2016 or 2015.

F-10

---

 

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.

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.

 

The Company periodically evaluates the realizable tax benefits of deferred tax assets and records a valuation allowance, if required, based on an estimate of the amount of deferred tax assets the Company believes does not meet the more likely than not criteria of being realized.  In certain circumstances, the deferred tax asset may exceed the amount permissible to be used under the tax law, for example, a net operating loss carryforward.  In such cases it is appropriate to write-off the excess net operating loss. At December 31, 2016, the Company wrote off $141.7 million of its net operating loss carryforward.  

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, 2016 or 2015.

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.

 

 

2. Recently Issued Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" in order to clarify the definition of a business as it relates to whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted under certain circumstances. We expect to adopt this guidance in the first quarter of 2018. The impact is not expected to be material.  

In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash" require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted under certain circumstances. We expect to adopt this guidance in the first quarter of 2018. Management is evaluating the provisions of this accounting standards update but considers it to have minimal  impact on our consolidated statements of cash flows given the immaterial amount of restricted cash on our balance sheet.

In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)" in order, to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The update addresses eight different transaction types and clarifies how to classify each in the statement of cash flows, where previously there was unclear or no specific guidance. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We expect to adopt this guidance in the first quarter of 2018. Management is evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated statements of cash flows and related disclosures.

F-11

---

 

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments", which introduces new guidance for estimating credit losses on certain types of financial instruments based on expected losses and the timing of the recognition of such losses. For public entities, this ASU is effective for annual periods beginning after December 15, 2019, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We expect to adopt this guidance in the first quarter of 2020. Management is evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

In March 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (“Update 2016-09”), which seeks to simplify several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, Update 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We will adopt this standard during the first quarter of 2017; we do not believe it will have a material effect on our consolidated results of operations, financial position or cash flows.

In February 2016, the FASB issued 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 results of operations, financial position or cash flows and anticipates adopting the guidance on the effective date of January 1, 2018.

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes” 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. Effective January 1, 2016, the Company early adopted ASU 2015-17 which was applied prospectively and therefore the adoption had no impact on the consolidated balance sheet as of December 31, 2015.

In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifiying 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 became effective for the Company as of January 1, 2016. The Company’s adoption of this guidance was applied retrospectively, and approximately $1.8 million was moved from assets to a direct deduction from the carrying amount of the debt on the Company’s consolidated financial statements.

In May 2014, August 2015 and May 2016, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” , ASU 2015-14,  “Revenue from Contracts with Customers, Deferral of the Effective Date”, ASU 2016-12,  “Revenue from Contracts with Customers, Narrow-Scope Improvements and Practical Expedients”, and ASU 2016-20, “Revenue from Contracts with Customers, Technical Corrections and Improvements”, respectively, as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle is that a company 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. It also requires entities to disclose both quantitative and qualitative information that enable financial statements users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This guidance is effective for annual periods beginning after December 15, 2017 with early adoption permitted on January 1, 2017 and shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. As we are in the process of evaluating the impact of the standard, we have not yet quantified the impact of adoption or determined the method of adoption. During 2017, we will perform the remainder of our implementation process, which will include quantification of impact, selection of adoption method and development of policies. The Company plans to adopt this guidance in the first quarter of 2018.

 

3. Acquisitions and Divestitures

On September 26, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. entered into a purchase and sale agreement with AVAD Energy Partners, LLC and Vendera Resources II, LLC to sell their remaining interest in producing wells and related oil and gas leases in its conventional properties located in multiple counties in Texas, effective as of July 1, 2016.  The sale price approximated $14,000,000.  The transaction closed on October 31, 2016.  In the third quarter of 2016, the Company reported an impairment charge of approximately $29.1 million, representing carrying value in excess of fair value, less the cost to sell the properties.

F-12

---

 

On August 2, 2016, Lonestar Resources US Inc. and Eagleford Gas 5, LLC (collectively, “Buyer”) entered into a purchase and sale agreement with Juneau Energy, LLC (“Juneau”) whereby the Company obtained an undivided 50% of Seller’s interest in two producing wells and each well’s respective oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas.  The total consideration paid by the Company was $5,500,000 payable in 500,227 shares of the Company’s Class A common stock.  As part of the purchase and sale agreement, the Company entered into a swap of assets of 50% of its interest in the Carter Lake - Wildcat area for 50% of the assets owned by Juneau in the 1,300 net mineral acres.  The Company owned 1,110 net mineral acres (“Swap Assets”) in the Carter Lake - Wildcat area on August 1, 2016.  As further part of the purchase and sale agreement, the Company agreed to commence operations on drilling one (1) Eagle Ford Shale well by December 31, 2016 on Juneau Energy, LLC’s assets or the Swap Assets; and, another Eagle Ford Shale well on Juneau Energy LLC’s assets or the Swap Assets by December 31, 2017.  As of December 31, 2016, the Company had commenced drilling operations of two (2) Eagle Ford Shale wells satisfying the drilling commitment provision under the purchase and sale agreement.   

On June 15, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. sold their entire interest in producing wells and related oil and gas leases in its Morgan’s Bluff property located in Orange County, Texas, effective as of July 1, 2016.  Production related to the property was 86 Boe/d during the second quarter of 2016.  The sale price approximated $2,200,000 and resulted in a gain of approximately $1,900,000. 

From January to March 2016 the Company paid approximately $770,000 to acquire approximately 220 net acres in La Salle County, TX surrounding Company developed areas and new undeveloped areas classified by the Company as Burns Ranch.  From January to June 2016 the Company paid approximately $1,600,000 to acquire approximately 1,088 net acres in Gonzales County, TX for new well development in the Cyclone area.

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 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, TX for $500,000 as a further component of the exchange.

 

 

4. Restricted Certificate of Deposit

The Company is required to maintain a certificate of deposit (“CD”) issued by a municipality in Montana, in which certain of our 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, 2018, 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 December 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 derivatives (realized and unrealized) are included in the consolidated statement of operations.

F-13

---

 

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

 

 

 

The above oil derivative contracts aggregate to 912,600 barrels or 2,500 barrels of oil per day for 2017 and 730,000 barrels or 2,000 barrels of oil per day for 2018. The above natural gas derivative contract equates to 7,000 MMBtu 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, 2016 and 2015, 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 contain credit-risk related contingent features.

 

 

6. Fair Value Measurements

Non-recurring fair value measurements include certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; warrants issued in equity offerings and the initial recognition of asset retirement obligations for which fair value is used. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these estimates as Level 3.

The Company periodically reviews for impairment its long-lived assets, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Based upon the sale of the Company’s conventional oil and natural gas properties located in Texas, the Company reviewed the carrying value of the remaining acreage in this area and recorded an impairment of approximately $29.1 million. During 2016, certain leased acreage was set to expire in Montana as part of the Bakken, Three Forks, and Lower Lodgepole formations (the “Poplar Properties”).  Based on our decision to defer drilling on the Poplar Properties, the Company recorded an approximate $1.9 million impairment charge related to leased acreage expiring during 2016.  This was calculated through the allocation of our current carrying value of the properties across our proportionate share of the acreage. Certain leased acreage in Wilson County, Texas expired in October 2016.  The Company decided to not extend those leases, therefore, the leasehold costs associated with this acreage was impaired as a result of these lease expirations.  The Company recorded an impairment charge of approximately $2.8 million. 

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.

F-14

---

 

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

 

 

 

Level 3 Gains and Losses

 

The table below sets forth a summary of changes in the fair value of the Company’s level 3 liability for the year ended December 31, 2016.

 

 

The derivative asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors. The Company typically has numerous hedge positions that span several time periods and often result in both derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets, including the deferred premiums associated with its hedge positions. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.

 

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, except for bonds, which are recorded at amortized cost less debt issuance costs.  The fair value of the “8.750% Senior Notes” (as defined in Note 10 below) approximates $139.3 million as of December 31, 2016, and the notes are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs.  The Company’s other Level 3 financial liabilities measured at fair value consist of the warrant liability as of December 31, 2016.

F-15

---

 

Significant unobservable inputs used in the fair value measurement of the warrants include the estimated term. Significant decreases in the estimated remaining period to exercise would result in a significantly lower fair value measurement.

  

 

 

7. Oil and Gas Properties

A summary of oil and gas properties follows:

 

 

 

8. 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 $2.5 million as of December 31, 2016.

The liability has been accreted to its present value as of December 31, 2016. The Company evaluated its wells and has determined a range of abandonment dates through December 2056.

The following represents a reconciliation of the asset retirement obligations:

 

 

 

9. Accrued Liabilities

The accrued liabilities consist of the following at December 31:

 

 

F-16

---

 

10. Long-Term Debt

The long-term debt consists of the following at December 31:

 

 

Senior Secured Credit Facility

On July 28, 2015, LRAI closed a new $500,000,000 Senior Secured Credit Facility (the “Senior Secured Credit Facility”) which replaced a $400,000,000 Wells Fargo-led syndicated facility.  The new facility was arranged by Citibank, N.A. and featured 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 represented 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.  Effective as of May 19, 2016, the borrowing base was reduced from $180,000,000 to $120,000,000.  As of December 31, 2016 (giving effect to the amended covenant ratio discussed below) and December 31, 2015, LRAI was in compliance with all covenants including all financial ratios under the Senior Secured Credit Facility.  As of December 31, 2016 and 2015, $43,500,000 and $87,000,000 was borrowed, respectively, under the Senior Secured Credit Facility.

The Senior Secured Credit Facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit.  The Senior Secured Credit Facility provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the Senior Secured Credit Facility.

Borrowings under the Senior Secured Credit Facility, at LRAI’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) 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 (3.64% at December 31, 2016).

The Senior Secured Credit Facility requires LRAI to maintain certain financial ratios and limits the amount of indebtedness LRAI can incur.  Subject to certain permitted liens, LRAI’s obligations under the Senior Secured 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 Senior Secured Credit Facility, LRAI and certain of its subsidiaries also entered into certain customary ancillary agreements and arrangements, which, among other things, provide that the indebtedness, obligations, and liabilities of the Company arising under or in connection with the Senior Secured Credit Facility are unconditionally guaranteed by such subsidiaries.

Effective as of July 27, 2016, LRAI, the several banks and other financial institutions party thereto (collectively, the “Consenting Lenders”) and Citibank, N.A., in its capacity as administrative agent for the lenders (the “Administrative Agent”) entered into the Third Amendment to Credit Agreement and Limited Waiver (the “Amendment”) to that certain Credit Agreement dated as of July 28, 2015, by and among LRAI, the Consenting Lenders (together with the other banks and financial institutions party thereto, the “Lenders”) and the Administrative Agent (as amended, supplemented and modified, the “Credit Agreement”) to (a) permit LRAI to incur the second lien obligations contemplated by the Securities Purchase Agreement with Leucadia National Corporation and others (as described below) and LRAI’s contemplated use of proceeds thereof, (b) increase the applicable margin for Eurodollar and ABR loans and letter of credit fees by 0.75% across all levels of the previously applicable pricing grid, (c) modify the fee payable on the actual daily unused amount of the aggregate commitments to a flat 0.50% across all levels of the pricing grid, (d) increase the minimum percentage of the value of LRAI’s oil and gas properties that must be mortgaged as collateral for the obligations under the Credit Agreement and the other loan documents from 80% to 90%, (e) modify the maximum leverage ratio thresholds from 4.0 to 1.0 to (i) 4.75 to 1.0 for the four quarterly periods ending June 30, 2016, (ii) 4.50 to 1.0 for the four quarterly periods ending September

F-17

---

 

30, 2016, (iii) 4.25 to 1.0 for the four quarterly periods ending December 31, 2016 and (iv) 4.00 to 1.0 for all periods thereafter, (f) prohibit distributions to the Predecessor for general and administrative expenses after September 30, 2016 and (g) amend certain other provisions of the Credit Agreement as more specifically set forth in the Amendment.

8.750% Senior Notes

On April 4, 2014, LRAI issued at par $220,000,000 of 8.750% Senior Unsecured Notes due April 15, 2019 (the “8.750% Senior 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 LRAI’s Senior Secured Credit Facility and 2nd lien facility both with Wells Fargo at this time, and for general corporate purposes. Under the 2nd lien term loan agreement, LRAI 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, LRAI may redeem the 8.750% Senior 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 8.750% Senior Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

 

 

In addition, upon a change of control of LRAI, holders of the 8.750% Senior Notes will have the right to require LRAI to repurchase all or any part of their 8.750% Senior Notes for cash at a price equal to 101% of the aggregate principal amount of the 8.750% Senior Notes repurchased, plus any accrued and unpaid interest. The 8.750% Senior Notes were issued under and governed by an Indenture dated April 4, 2014, between LRAI, Wells Fargo Bank, National Association, as trustee and LRAI’s subsidiaries named therein as guarantors (the “Indenture”). The Indenture contains covenants that, among other things, limit the ability of LRAI 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 LRAI’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. At December 31, 2016 and 2015, the Company had approximately $1,200,000 and $1,100,000, respectively, of debt issuance costs associated with issuance of the Senior Secured Credit Facility remaining that are being amortized over the lives of the respective debt which are recorded as other non-current assets in the consolidated balance sheets.

Securities Purchase Agreement and Second Lien Notes

On August 2, 2016, the Company entered into a Securities Purchase Agreement with Juneau Energy, LLC, as initial purchaser (“Juneau”), Leucadia National Corporation (“Leucadia”), as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of  (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share (the “Warrants”).The balance of these notes and warrants is reflected in our long-term debt – related parties and equity warrant liability – related parties on the face of the balance sheet.

The Second Lien Notes are secured by second-priority liens on substantially all of LRAI’s and its subsidiaries’ assets to the extent such assets secure obligations under the Senior Secured Credit Facility.

 

During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 760,000 shares of its Class A common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance.  The warrants were adjusted to fair value at December 31, 2016 which resulted in an unrealized gain on warrants of approximately $0.6 million. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes  in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts

F-18

---

 

paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million.

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering.

Repurchase Facilitation Agreement

On October 26, 2016, effective September 29, 2016, Lonestar Resources US, Inc. (the “Company”), by and on behalf of itself and certain of its subsidiaries, entered into an Amended and Restated Repurchase Facilitation Agreement (the “Amended and Restated Agreement”) with Seaport Global Securities LLC, a Delaware limited liability company (“Seaport Global”).  Pursuant to the Amended and Restated Agreement, Seaport Global has agreed to provide the Company with financing (“Gap Financing”) from time to time in connection with the repurchase of the 8.750% Senior Notes , to be acquired by Seaport Global on the Company’s behalf in one or more open market purchases.  

As of September 30, 2016, the Company recorded $2,063,320 as long-term debt on its balance sheet as a result of this financing.  In December 2016, LRAI repaid the Gap Financing with proceeds from the 2016 Common Stock Offering.

 

 

11. Income Taxes

The current and deferred components of income tax expense (benefit) are as follows:

 

 

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 actual income tax provision amounts from the expected income tax provision amount by applying the U.S. federal statutory corporate income tax rate of 35% for the periods indicated:

 

 

F-19

---

 

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:

 

 

The net operating loss carryforward as of December 31, 2016, approximates $199.9 million and begins to expire in 2030. The deferred tax asset recorded for the net operating losses does not include $2.2 million of deductions for excess stock-based compensation.  

 

On December 22, 2016, the Company completed a public offering of 13.8 million of its Class A common stock.  A change of ownership, as defined under the provisions of Section 382 of the Internal Revenue Code (“IRC”) occurred on this date.   A portion of our net operating loss and tax credit carryforwards will be limited in future periods.  IRC Section 382 places limitations on the amount of taxable income which may be offset by tax carryforward attributes, such as net operating losses or tax credits after a change of ownership event.  As a result of this ownership change, certain of our accumulated net operating losses will be subject to an annual limitation regarding their utilization against taxable income in future periods.  The 2016 change creates an estimated annual utilization limit of approximately $1.0 million on our ability to utilize net operating losses generated prior to the ownership change event.   Built-in gains associated with our deferred tax attributes on the date of the ownership change may increase the net operating loss utilization limit in future periods, allowing additional utilization of net operating losses generated prior to the date of the ownership change. Due to the ownership change and the resulting limitation on the utilization of net operating loss generated prior to the change, an estimated $141.7 million of the net operating loss carryforwards have been written off in 2016.  If the Company were to experience another ownership change in future periods, the net operating loss carryforwards may be subject to additional utilization limits.  The Company has approximately $10 million 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, 2016, 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.

 

 

F-20

---

 

12. Stockholders’ Equity and Stock Based Compensation

Common Stock Issuances

On December 22, 2016, the Company completed the 2016 Common Stock Offering of 13.8 million shares of its Class A common stock at a price of $5.75 per share, for proceeds of approximately $71.8 million, net of offering costs.  The Company used the net proceeds from the stock offering to repay borrowings under its Senior Secured Credit Facility, Second Lien Notes and to repay the debt owed under the Facilitation Agreement with Seaport Global.

On August 2, 2016, the Company entered into a purchase and sale agreement with Juneau Energy, LLC (“Juneau”) whereby the Company obtained an undivided 50% of Juneau’s interest in two producing wells and each well’s respective oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas.  The total consideration paid by the Company was $5,500,000 payable in 500,227 shares of the Company’s Class A common stock.

In July 2016, the Company issued 2,500 shares of Class B non-voting common stock to Butterfly Flaps, Ltd., a Company in which Dr. Christopher Rowland (a director of the Company) owns an interest.  The shares were issued for services to be performed by Butterfly Flaps, Ltd. in 2017.

Determining Fair Value of Stock Options

In determining the fair value of stock option grants, the Company utilized the following assumptions:

Valuation and Amortization Method. The Company estimates the fair value of stock option awards on the date of grant using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method.”

Expected Life. The expected life of stock options granted represents the period of time that stock options are expected, on average, to be outstanding.  The Company determined the expected life to be 3.5 years, for all stock options issued with three-year vesting periods and four-year grant expirations.

Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of Predecessor’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 Predecessor’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. The Predecessor and the Successor have not paid any cash dividends on its common shares, and the Successor 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 year ended December 31, 2016, no stock options were exercised.  The following tables summarize certain information related to outstanding stock options under the Lonestar Resources Limited 2012 Employee Share Option Plan and the Lonestar Resources US Inc. 2016 Incentive Plan, which replaced the Lonestar Resources Limited 2012 Employee Share Option Plan following the Reorganization:

 

F-21

---

 

 

 

Stock-Based Compensation Expense

For the years ended December 31, 2016 and 2015, the Company recorded stock-based compensation expense for stock options granted using the fair-value method of approximately $448,000 and $2,585,000, respectively.  As all outstanding options have fully vested, no unrecognized compensation cost existed at December 31, 2016.

 

 

13. 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.  The Company includes the number of stock options in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s Class A common stock for the period. When a loss from operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding.  There is no dilutive effect for the years ended December 31, 2016 and 2015 as the Company reported a loss from operations for those periods.  

The following table presents unaudited 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 the year ended December 31, 2015:

Unaudited Earnings Per Share (After Reorganization)

 

 

 

14. Related Party Activities

Leucadia

On August 2, 2016, LRAI and the Company entered into the Purchase Agreement with Juneau, Leucadia, as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of Second Lien Notes and (ii) Warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock. Pursuant to the Purchase Agreement Juneau purchased $13,000,000 aggregate principal amount of Second Lien Notes and Warrants to purchase 500,000 shares of Class A common stock.

F-22

---

 

On August 2, 2016, the Company also issued 500,227 shares of Class A common stock to Juneau pursuant in exchange for interests in certain oil and gas assets pursuant to a purchase and sale agreement (the “Purchase and Sale Agreement”). As part of the Purchase and Sale Agreement, the Company entered into a swap of assets of 50% of its interest in the Carter Lake - Wildcat area for 50% of the assets owned by Juneau in the 1,300 net mineral acres.  The Company owned 1,110 net mineral acres (“Swap Assets”) in the Carter Lake - Wildcat area on August 1, 2016.  As further part of the Purchase and Sale Agreement, the Company agreed to commence operations on drilling one (1) Eagle Ford Shale well by December 31, 2016 on Juneau Energy, LLC’s assets or the Swap Assets; and, another Eagle Ford Shale well on Juneau Energy LLC’s assets or the Swap Assets by December 31, 2017.  As of December 31, 2016, the Company had commenced drilling operations of two (2) Eagle Ford Shale wells satisfying the drilling commitment provision under the Purchase and Sale Agreement.

Due to Leucadia’s ownership interests in Juneau, Leucadia is considered to be the beneficial owner of shares Juneau owns. As a result of the Warrants and Class A common stock issuances to Juneau in connection with the Purchase Agreement and the Purchase and Sale Agreement, respectively, Leucadia is the beneficial owner of more than 10% of the Company’s Class A common stock.

In connection with entering into the Purchase Agreement, the Company also entered into a Registration Rights Agreement and an equity commitment agreement, both dated as of August 2, 2016. Pursuant to the Registration Rights Agreement, the Company has agreed to register for resale certain Class A common stock issued or issuable to Juneau and Leucadia, including those issuable upon exercise of the Warrants. Leucadia has agreed, pursuant to the equity commitment agreement, to purchase a certain number of Class A common stock equal to (a) $20,000,000 (or such lesser amount as the Company requests) divided by (b) the offering price to investors in a registered public offering of securities that is completed on or before December 31, 2016.  On December 22, 2016 Leucadia purchased 3,478,261 shares of Class A voting common stock (costing $20,000,000), thus satisfying the equity commitment. In connection with Leucadia’s commitment, the Company agreed to pay Leucadia a fee equal to $1,000,000, payable upon the closing of such offering.  This amount was recorded in accounts payable in the consolidated balance sheet at December 31, 2016.  This amount was paid on January 3, 2017.

EF Realisation

On October 26, 2016, the Company entered into a Board Representation Agreement (“Board Representation Agreement”) with EF Realisation. Under the Board Representation Agreement, for as long as EF Realisation owns 15% or more of the issued and outstanding shares of our Class A common stock, it has the right to nominate up to, but no more than, two directors to serve on our Board of Directors and for as long as EF Realisation owns at least 10% but less than 15% of our issued and outstanding shares of Class A common stock, it has the right to nominate up to, but no more than, one director to serve on our Board of Directors.

On October 26, 2016, the Company entered into a Registration Rights Agreement with EF Realisation, pursuant to which we agreed to register for resale Class A common stock held by EF Realisation. We have agreed to file a registration statement providing for the resale of Class A common stock held by EF Realisation no later than the earlier of (i) October 26, 2017, and (ii) 30 days after the date we first become eligible to file a registration statement on Form S-3. We have also granted EF Realisation certain piggyback and demand registration rights.

Frank D. Bracken III and Thomas H. Olle

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.

Dr. Christopher Rowland

Butterfly Flaps, Ltd, a company in which Dr. Christopher Rowland (a director of the Company) owns an interest, has performed consultancy work for the Company since 2013 covering various strategic, tax structuring and investor matters at a cost of approximately $25,000 per quarter.  In July 2016, the Company issued 2,500 shares of Class B non-voting common stock to Butterfly Flaps, Ltd. The shares were issued for services to be performed by Butterfly Flaps, Ltd. in 2017.

Daniel R. Lockwood

New Tech Global Ventures, LLC, a company in which Daniel R. Lockwood (a director of the Company) owns a limited partnership interest, has provided field engineering staff and consultancy services for the Company since 2013. The total cost for such services was approximately $665,000 and $938,000 for the years ended December 31, 2016 and 2015, respectively. 

Mitchell Wells

Mitchell Wells, who served as our director since December 2014 until his resignation in January 2017, has provided consultancy services as our Company Secretary since January 2013. These services have been provided through BlueSkye Pty Ltd, for which Mr.

F-23

---

 

Wells is the sole Director and shareholder. BlueSkye Pty Ltd was paid approximately $95,000 and $142,500 for the years ended December 31, 2016 and 2015, respectively.  He has not received any additional compensation for his service as a Director.

 

 

15. 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:

 

 

Rent expense was $375,000 and $404,000 for the years ended December 31, 2016 and 2015, respectively.

Rig Contract

As of December 31, 2016, the Company had one drilling rig under contract. The contract provided for a daily drilling rate of $15,000. The rig contract terminates on July 8, 2017. The early termination fee is equal to 80% of the daily drilling rate times the number of days remaining on the contract term. Using the $15,000 daily rate, as of December 31, 2016 the minimum remaining commitment per the terms of the agreement was approximately $2.7 million.

As of December 31, 2015, the Company had one drilling rig under contract. The contract provided 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 terminated 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 was approximately $3.8 million.

 

 

 

 

 

 

F-24

---

 

16. Supplemental Cash Flow Information

Supplemental disclosures to the consolidated statements of cash flows are presented below:

 

 

16. 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.  We are unaware of any material additional disclosures that should be made to these financial statements.

      

 

   

 

 

F-25

---

 

Lonestar Resources US Inc.

Unaudited Supplementary Information

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

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:

 

 

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

 

 

Results of Operations

The following table sets for the results of operations from oil and gas producing activities for the years ended December 31, 2016 and 2015.

 

 

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.

F-26

---

 

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.

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, 2016 and 2015. 

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, 2016 and 2015, calculations were made using average prices of $42.75 and $50.28 per barrel of crude oil, respectively, and $2.46 and $2.59 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.

F-27

---

 

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, 2016 and 2015 were as follows:

 

 

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:

 

 

 

F-28