Lonestar Resources, Ltd. - energyprospectus.com · 1/7/2016 · Lonestar Resources, Ltd. January...

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Lonestar Resources, Ltd.

January 7, 2016

Commentary by Dan Steffens Lonestar Resources, Ltd. (OTCQX: LNREF) is one of the companies in our Small-Cap Growth Portfolio. It is focused on developing its leasehold in the South Texas Eagle Ford Play. Current production is approximately 6,800 Boepd (~68% crude oil) with steady growth expected to over 8,000 Boepd in 2016. Well-funded small-caps with lots of running room have the potential for explosive share price appreciation when oil & gas prices rebound.

During the last five years, Lonestar has steadily increased its production, proven reserves and low-risk drilling inventory. It is heavily weighted to oil and they recently increased production guidance. Their hedge position insures solid top line revenues through December 31, 2016.

Based on my forecast model (attached below), Lonestar should generate more than $3.80 operating cash flow per share in 2015 and approximately $3.50 per share in 2016. They recently announced an upsizing and extension of their bank credit facility, which gives the company more than enough liquidity to fund continued growth. See Hedge Positions below.

Management Frank D. Bracken III, CEO, Director Barry D. Schneider, COO Tom H. Olle, SVP Operations Douglas W. Banister, CFO Jana Payne, VP, Geology

www.lonestarresources.com



January 7, 2016

The only explanation that I can give for Lonestar’s low share price is that it does not trade on a major U.S. exchange. On December 16, 2015 the company announced a plan that should have the shares trading on the NASDAQ by the end of March, 2016. I believe this move will draw a lot more attention to this rapidly growing small-cap E&P company. Since our last profile, Lonestar has announce a significant addition to the company’s management team. Jana Payne joined as Vice-President of Geology in November 2015 bringing over 25 years of experience in the oil and gas industry. Prior to joining Lonestar, Ms. Payne held the position of Senior Exploitation Manager and Geologist at Halcon Resources, Inc. Ms. Payne spent seven years at Petrohawk Energy Inc. in (and subsequently BHP Billiton SA post its acquisition of Petrohawk, Inc.), where her initial mapping of the Eagle Ford shale across nine counties 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.

My Fair Value Estimate for LNREF is now $12.00/share

Compares to First Call’s Price Target of $8.19

Disclosure: I do not have a position in LNREF and I do not intend on buying or selling it in the next 72 hours. I wrote this profile myself, and it expresses my own opinions. I am not receiving compensation for it from the company. I have no business relationship with any company whose stock is mentioned in this article.

Company Overview Lonestar Resources, Ltd. (ASX: LNR, OTCQX: LNREF) is focused on the acquisition, development and production of unconventional resources in the United States. While optimizing cash flows from its Conventional assets, Lonestar is focusing its attention and capital to continuing its growth strategy in the Eagle Ford Shale. Lonestar currently operates 100% of its 35,487 net acres in the Eagle Ford, and continues to expand its leasehold. Lonestar believes it is capitalized to fund the development of its existing Eagle Ford Shale drilling inventory through internal means. Lonestar is also engaged in an early-stage project in the Bakken Petroleum System, where it has assembled a 52,559 acre leasehold (34,163 net acres) and tested light oil from the Bakken, Three Forks and Lower Lodgepole formations.



January 7, 2016

2014 Reserves For the year ended December 31, 2014, Lonestar’s independent reserve reports and PV10 estimates employed the commodity pricing conventions prescribed by the U.S. Securities & Exchange Commission (SEC), which employs past 12 months pricing for the projections. Use of SEC methodology allows the Company’s results to be compared more directly with its U.S. peers. Based on the results generated from the independent consultants report for the year ended December 31, 2014, Proved Reserves net of royalties were 31.0 million barrels of oil equivalent (MMBOE), an increase of 70% over the 18.2 MMBOE reported at year ended December 31, 2013. Lonestar’s Proved Reserve PV10 value of US$705.8 million represents an increase of 65% over 2013 levels.



January 7, 2016

Lonestar’s Proved Reserves include 23.6 million barrels of crude oil and condensate, 3.0 million barrels of natural gas liquids, and 26.0 billion cubic feet of natural gas. By energy content, Lonestar’s Proved Reserves are weighted 86% to liquids. Further, Lonestar’s Proved Reserve base is comprised of 89% unconventional reserves and 11% conventional, by volume. Lastly, the Company’s Proved Reserves represent an excellent balance between Proved Developed (40%) and Proved Undeveloped (60%). At December 31, 2014, Proved & Probable Reserves (2P) were 43.2 million barrels of oil equivalent, which included 34.3 million barrels of oil, 3.7 million barrels of NGL’s, and 31.3 billion cubic feet of natural gas, and had an associated PV10 value of $859.7 million. These results represent a 70% increase in Proved and Probable reserves and a 75% increase in the associated PV10 value.



January 7, 2016

At December 31, 2014, Proved, Probable & Possible Reserves (3P) were 48.1 million barrels of oil equivalent, which included 38.5 million barrels of oil, 4.0 million barrels of NGL’s, and 33.7 billion cubic feet of natural gas, and had an associated PV10 value of $952.2 million. These results represent a 90% increase in Proved, Probable & Possible reserves and a 94% increase in the associated PV10 value. Importantly, Lonestar’s inventory of Engineered Locations, those designated as Proved, Probable or Possible, are associated with an estimated 78% of its greater than 30,000 net acres in the Eagle Ford Shale. Lonestar believes that industry activity may establish additional viable drilling locations at no cost to the Company. It is this large inventory of drilling locations that may serve as the fuel for organic reserve growth in the future.



January 7, 2016

2015 Third Quarter Update Highlights

• Lonestar set a new production record, reporting a 42% increase in net oil and gas production to 6,614 BOEPD in 3Q15, vs. 4,669 BOEPD in 3Q14. Lonestar’s 3Q15 sales volumes also represented a 14% sequential increase over 2Q15 production levels. In the third quarter, 83% of the Company’s production was crude oil and NGLs.

• The Company’s Eagle Ford Shale properties registered a 51% increase in net oil and gas production over 3Q14 results, to 5,969 BOEPD, which was 17% sequential growth.

• EBITDAX was $21.7 million for 3Q15 vs. $23.4 million for 3Q14, as increased production volumes and incremental revenues from crude oil hedges largely offset a 52% decrease in West Texas Intermediate oil prices. EBITDAX dropped just 2% against 2Q15 results as production growth largely offset a $12 per barrel drop in WTI. EBITDAX further benefited from the Company’s ability to reduce LOE per BOE 18% sequentially.

• Lonestar reported Net Income of $7.4 million for 3Q15 vs. a Net Income of $19.1 million in 3Q14. Excluding a $10.7 million unrealized gain on commodity derivative and the associated non-cash expense, Lonestar would have reported Net Income of $0.5 million for 3Q15, equating to $0.04 per share.

• At September 30, 2015, $79 million was outstanding on the company’s credit facility, leaving $101 million undrawn and available. The lead agent of its Senior Secured lender group has recommended that the borrowing base be reaffirmed at $180 million. Subsequently, as noted below, Lonestar received official confirmation on November 13, 2015.

• Lonestar continues to build production momentum, with the Company’s volumes exceeding 7,500 BOEPD in October, setting the stage for another production record in the fourth quarter of 2015.

• Production from its Eagle Ford Shale properties is outperforming expectations. Based on a 2015 WTI price range of $50 to $60 per barrel and the expectation for the Company to drill 15 gross wells in 2015, Lonestar has increased the low end of its guidance and now forecasts production will average between 6,100 and 6,300 BOEPD, yielding EBITDAX guidance of $84 to $90 million for 2015. More than 50% of Q4 2015 oil production was hedged at $82.58/bbl.

Financial Update Lonestar continues to make strides towards its core goal of expanding its resource base during the current downturn in commodity prices. Lonestar’s preference is to use its flexible drilling schedule to gain access to additional leasehold and reserves in proven areas via farm-in, supplemented by primary term leases. This strategy allows Lonestar to grow its asset base without straining its liquidity, as the Company continues to retain its borrowing base liquidity in anticipation of a growing number of distressed sales in South Texas as the effects of a downturn in commodity prices are amplified.



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• On July 27, 2015, Lonestar closed a new $100 million drilling joint venture with IOG Capital, L.P., an

investment partnership led by industry veteran Marc Rowland and partnered with Fortress Investment Group, who has $69.9 billion in assets under management and Metalmark Capital, a private equity firm which is currently investing its latest fund with $2.5 billion. As a group, IOG Capital has committed capital of $700 million. The joint venture calls for IOG Capital to participate as a non-operated working interest partner in Lonestar’s drilling program, and at Lonestar’s option, on a promoted basis. This off-balance sheet financing provides Lonestar with the ability to pursue more acreage-adding and reserve-adding deals with the drillbit, while allowing it to maintain its balance sheet discipline.

• On July 28, 2015, Lonestar closed a new $500 million Senior Secured Revolving Credit Facility led by Citibank, N.A.. The initial borrowing base has been set at $180 million, a 20% increase over its prior level of $150 million. At June 30, 2015, $76 million was outstanding on the facility leaving $104 million available, on a pro forma basis. The new revolving credit facility offers several positive features, including: an extension in the maturity from March, 2018 to October, 2018; a 0.25% reduction in interest rate spreads; the capacity to hedge higher levels of oil and gas production; and the addition of three prominent banks, BBVA Compass, Comerica Bank, and Barclays Bank.

• On November 13, 2015, Lonestar announced that pursuant to the terms of the Company’s Senior Secured Credit Facility, which is redetermined semiannually, the Company’s Borrowing Base has been reaffirmed at $180 million. As of September 30th, 2015, the company had $79 million outstanding on the facility, leaving $101 million undrawn and available.

Operations Update

• Lonestar set another production record in the third quarter of 2015, registering sequential production growth of 14% over 2Q15 levels. The Company’s net production for the third quarter of 2015 also represented a 42% increase over 3Q14 levels, rising to 6,614 BOEPD. Lonestar’s Eagle Ford Shale drilling program continues to be the driver for the Company’s record-setting production. Third quarter 2015 volumes were comprised of 4,631 barrels of oil per day, 840 barrels of NGL’s per day, and 6,863 Mcf of natural gas per day. Third quarter 2015 production was comprised of 83% crude oil and natural gas liquids, and 17% natural gas.

• During the third quarter of 2015, Lonestar achieved considerable improvement in its lease operating expenses. Total Company lease operating expenses were $4.8 million, marginally above results one year ago, but down 4% sequentially from second quarter 2015 results. Continued production growth and cost containment combined to reduce Lonestar’s lease operating expense on a unit basis by 17% from $9.43 per BOE in 2Q15 to $7.83 per BOE in the most recent quarter. Lonestar believes that continued production growth and cost reduction efforts should further reduce LOE per BOE in the fourth quarter of 2015.

• In the third quarter of 2015, Lonestar generated EBITDAX of $21.7 million, a 7% decrease from the 3Q14 EBITDAX of $23.4 million. A 42% increase in oil and gas production and a strong hedge position largely offset a 53% decrease in wellhead price realizations. Strong production growth and reductions in lease operating costs allowed EBITDAX to remain essentially flat versus 2Q15 results, despite a 20% decrease in



January 7, 2016

WTI benchmark pricing, quarter to quarter. • As has been Lonestar’s practice since inception, crude oil hedging has been a key element to providing

visibility to cash flow streams and associated liquidity in the current crude oil price environment. Currently, the Company has West Texas Intermediate swaps covering 2,551 barrels of oil per day for the remainder of 2015 at an average strike price of $82.23 per barrel and WTI swaps covering 2,276 barrels of oil per day for calendar 2016 at an average strike price of $77.15 per barrel. The Company has also entered into three-way collars covering 1,000 bopd in 2017 which provide an effective floor of $55.25 per barrel with WTI prices between $40.00 per barrel and $60.00 per barrel but also gives upside to $80.25 per barrel.



January 7, 2016

Operations Eagle Ford Shale Trend – Western Region Asherton – In central Dimmit County, no new wells were completed during the quarter. However, production rates from the 4 producing wells continued to outperform the third-party engineering projections. The Asherton leasehold is held by Production, and Lonestar does not plan drilling activity here in the remainder of 2015 or 2016. Beall Ranch – In Dimmit County, Lonestar drilled and completed the Beall Ranch #26H-#28H during the third quarter of 2015. These wells were drilled to an average total depth of 11,500 feet in an average of 10 days, compared to the AFE of 13 days. These wells are short laterals, possessing an average perforated interval of 3,200 feet. Lonestar achieved completed well costs of $3.3 million versus Lonestar’s predrill AFE of $3.7 million. While Lonestar has been developing Beall Ranch for over four years now, the Company continues to strive for improved



January 7, 2016

results. Based on advanced log analysis, the #26H-28H wells were drilled in a narrower, refined target zone within the Eagle Ford Shale, and were fracked with markedly tighter stage spacing, achieving an average proppant concentration of 1,654 pounds per foot. The 3 new wells registered average Max-30 production rates of 329 bopd and 389 Mcfgpd, or a 3-stream rate of 419 BOEPD, on an 18/64” choke. Recent rates, achieved in the wells’ 105th day of production were still averaging 365 BOEPD per well. To date, Lonestar’s refinements to its targeting and stimulation designs appear to be achieving material improvements in recovery rates, with the #26H-28H producing 43% more oil per perforated foot than the #32-#34H, which are immediate offsets, and were completed in 2014.

Burns Ranch Area – In northern La Salle County, Lonestar drilled and completed the Burns Ranch Eagle Ford Unit A #1H-3H wells with an average perforated interval of 7,970 feet. The three new wells, which were pad-drilled and zipper fracked with an average proppant concentration of 1,570 pounds per foot, registered average Max-30 production rates of 486 bopd and 405 Mcfgpd, or 580 BOEPD, on a 22/64” choke. Recent rates, achieved in the



January 7, 2016

wells’ 180th day of production, were still averaging 390 BOEPD per well without artificial lift. Lonestar is extremely pleased with the results of its initial long laterals on the Burns Ranch and currently plans to drill additional wells on this property in 2016 which are currently categorized as Probable Undeveloped. Horned Frog – In La Salle County, Lonestar drilled and completed the Horned Frog A #1H & B #1H with an average perforated interval of 8,233 feet. The two new wells were fracked with an average proppant concentration of 1,556 pounds per foot. The Horned Frog A #1H tested 275 bopd and 5,527 Mcfgpd, or 1,542 BOEPD on a processed three-stream basis on a 20/64” choke and registered a 30-day production rate of 1,438 BOEPD. The Horned Frog B #1H tested 286 bopd and 5,311 Mcfgpd, or 1,658 BOEPD on a processed three-stream basis on a 20/64” choke and registered a 30-day production rate of 1,315 BOEPD. Lonestar continues to expand its leasehold position in the Horned Frog area. Since last report, Lonestar leased an additional 465 net acres, spending less than $0.5 million on lease bonuses to acquire these interests. Lonestar’s current net leasehold stands at 4,402 gross / 4,063 net acres at Horned Frog. Lonestar continues to evaluate a number of additional opportunities to grow its leasehold and reserves position in the vicinity of its Horned Frog acreage. Lonestar is currently drilling the Horned Frog D #1H & E #1H utilizing the IOG Capital Joint Venture in order to secure the aforementioned additional acreage. The Horned Frog D#1H & E #1H have been drilled and cased to an average total measured depth of 19,400 feet equating to an average perforated interval of 9,100 feet. Fracture stimulation is scheduled for mid-November with flowback expected to commence in early December. Lonestar is paying 10% of the well costs and will have an initial 15.0% working interest in these wells. Upon achievement of a specified IRR, Lonestar’s working interest would increase to 57.5%. Eagle Ford Shale Trend – Central Region Pirate Area – In southwest Wilson County, Lonestar has drilled the Pirate #M1H and Pirate #N1H wells and cased them to an average measured depth of approximately 16,100 feet. Lonestar has a 100% working interest and an average 76.4% net revenue interest in these two wells. The Pirate #N1 well is being drilled on leasehold which Lonestar was able to obtain via a farm-in of 197 gross / 197 net acres which are contiguous to the Company’s Pirate leasehold position, a transaction that was completed during the second quarter of 2015 in exchange for an overriding royalty interest. These wells are awaiting fracture stimulation at a date which has yet to be determined. Southern Gonzales County – In Gonzales County, Lonestar’s Harvey Johnson #1H-#6H continue to perform extremely well, with production from the six wells averaging 2,201 gross / 826 net BOEPD in the third quarter of 2015. Lonestar recently reached agreement to lease a total of 662 net acres which will accommodate 10 gross laterals with average lateral lengths of 7,200 feet. Lonestar is actively evaluating additional leasehold opportunities in the area.



January 7, 2016

Eagle Ford Shale Trend – Eastern Region Brazos and Robertson Counties – In Brazos Central County, Lonestar has permitted two 8,000-foot laterals. These wells are currently scheduled to be drilled on its Wildcat project in December, 2015. Lonestar has assembled a lease position while allowing other operators to drill and produce wells in the area, which reduces risk. The Company is encouraged by the results of offset drilling by a leading operator, who recently announced impressive production rates on four wells immediately offsetting Lonestar’s leasehold. It has been reported that the 5,527’ Rae #3H registered 30-day rates of 1,587 BOEPD while the 5,494’ Rae #4H produced 1,520 BOEPD. The nearest of these wells are approximately 3,000 feet east of Lonestar’s drilling locations. Additionally, it has been reported that the 6,841’ Walker Family #1H registered 30-day rates of 1,897 BOEPD while the 6,841’ Walker Family #3H produced 1,973 BOEPD. The nearest of these wells are 3,300 feet northeast of Lonestar’s drilling locations.



January 7, 2016

Bakken-Three Forks Trend Poplar West, Montana – Based on its geological analysis, core evaluation, and production testing, the Poplar West project area is prospective for the entire unconventional resource “Bakken Petroleum System”, which includes the Basal Lodgepole, Upper Bakken Shale, Middle Bakken, Lower Bakken Shale and the Third and Fourth Benches of the Three Forks formations. Further, Poplar West is highly prospective for the Amsden, Charles, Heath, Mission Canyon and Nisku formations. After processing and interpreting its 105 square miles of 3-D seismic data covering the Poplar West project area, Lonestar and its partners have identified 39 Charles prospects (conventional) and 41 Nisku prospects (conventional) and a total of 340 drilling locations in the Non-conventional Bakken Petroleum System. In October 2015, Lonestar received approval of the Stone Turtle Indian Exploratory unit by the Bureau of Land Management (BLM) and Bureau of Indian Affairs (BIA), which it has downsized to cover 44,084 gross / 28,655 net acres, with additional leasehold around the Unit’s periphery. The unit establishes a 5-year primary term on all leasehold in the unit, in exchange for drilling activity. The long-awaited unit approval opens the door for development of the block either by Lonestar or a farm-in partner. Recent Activity Joint Development Agreement On July 28, 2015, Lonestar announced the closing of a $100 million Joint Development Agreement (“JDA”) with IOG Capital, L.P. The Agreement provides incremental non-recourse capital for Lonestar to drill wells in its focus area of the Eagle Ford Shale play. Lonestar’s agreement with IOG Capital makes available a maximum of $100 million in funds to be used in drilling incremental Eagle Ford Shale wells. The Joint Development Agreement, which calls for IOG to participate as a non-operated working interest owner, states that the funds can be deployed towards the drilling and completion of Eagle Ford Shale wells which meet the collective return criteria of Lonestar and IOG. The JDA calls for IOG to contribute up to 90% of the initial capital for wells drilled in the program, with Lonestar contributing the remainder of well costs. After IOG achieves a specified return, Lonestar’s working interest would increase to 90%.

“Our deal with IOG Capital is tailor-made for Lonestar’s strategy in the current market. It makes sense to pursue additional growth opportunities in the current market, but do so in a manner that is consistent with Lonestar’s philosophy of maintaining balance sheet flexibility. First and foremost, this Agreement will allow Lonestar to more aggressively pursue additional farm-in opportunities without materially augmenting our capital budget. Farm-ins have been a principal source of leasehold and reserve growth for Lonestar in 2015, and we see that trend continuing… The Joint Development Agreement will also allow Lonestar to spread its drilling capital over a larger number of wells, which should have positive benefits in terms of scale, as well as enlarge the number and size of acquisitions the Company can



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prosecute, which makes sense for a company our size.” – Frank D. Bracken, III, Managing Director and Chief Executive Officer

Senior Secured Credit Facility On July 28, 2015, Lonestar announced the closing of a new $500 million Senior Secured Credit Facility, which replaces its previous $400 million facility. Lonestar’s new facility was arranged by Citibank, N.A., and importantly, features an expanded borrowing base of $180 million, an increase of $30 million associated with the $150 million borrowing base under its previous facility. There are several additional upgraded features related to the new facility which include:

• Improved Liquidity- At June 30, 2015, Lonestar had $76 million drawn on its facility, yielding $74 million of liquidity. Pro forma its new facility, liquidity is $104 million, an improvement of 41 percent.

• Reduction in Interest Rate Grid- Under its new facility, the spread over LIBOR interest rates is 25 basis points better than under its previous facility. At current levels, Lonestar’s interest rate has been reduced from 2.73% to 2.48%.

• Extension in Maturity Date – Lonestar’s new credit facility matures on October 16, 2018, representing a 7 month of extension versus its prior facility.

• Expanded Bank Group- ABN Amro, Texas Capital Bank and Bank of Texas each expanded their commitments under the new facility. Additionally, Lonestar added considerable firepower to the long-term capacity of the facility by adding three new banks: Comerica, BBVA Compass, and Barclays.

“We are extremely pleased with our expanded facility. It provides immediate benefits of increased capital availability at a lower interest cost. The facility also affords Lonestar an enhanced ability to hedge while leaving that decision completely at the discretion of the Company. Longer term, the facility’s maturity is extended by 20% and the increased number of large lenders in our group gives Lonestar the capability to substantially expand borrowing base among current lenders, which should streamline future expansions in the credit facility.” – Frank D. Bracken, III, Managing Director and Chief Executive Officer

Re-Domiciliation of Company On December 16, 2015, Lonestar announced that it is implementing a shift in its domicile from Australia to the United States and listing its shares on NASDAQ. Subject to shareholder and regulatory approvals, Lonestar expects this re-domiciliation and listing to become effective late March 2016.

Lonestar’s Chief Executive Officer, Frank D. Bracken, III commented, “I am pleased to announce a definitive plan which the Lonestar Board believes can achieve significant benefits for our security holders that may include:• A change in domicile to the US is more appropriate considering that 100% of the Company’s assets and



January 7, 2016

operational management are in the US. Moreover, changing the domicile to the US simplifies merger and sale transactions that the Group may enter into in the future, from both a structuring and tax perspective.

• Listing on NASDAQ should increase the attractiveness of Lonestar to US investors who are more familiar with US unconventional oil and gas reserves, and have a deeper pool of capital to deploy to such assets.

• An improved valuation and better trading liquidity is expected for the shares of Lonestar US and should result in demand from US-based investors that do not traditionally invest in equities listed outside of the US.

• Current valuations for Eagle Ford Shale assets are materially higher for Lonestar’s peers traded on US exchanges than for the Company, which trade on the Australian Securities Exchange. Applying these US-listed peer group multiples indicates a possible substantial lift in Lonestar’s share price and market capitalization (although there can be no assurance as to the NASDAQ trading price of Lonestar US shares).

• Re-domiciling in the US and listing on NASDAQ will better align the Group’s corporate structure with Lonestar’s assets and management. Over the medium-term it should reduce the group’s cost of capital and increase the attractiveness of the group to potential merger partners or acquirers.

In January 2016, Lonestar Resources US, Inc. will submit its listing application to NASDAQ and has already reserved the ticker symbol "LONE". A first Court Hearing for the Scheme of Implementation has been scheduled with the Federal Court of Australia for early February 2016. 2015 Drilling and Completion Plans Lonestar currently intends to run a one-rig program in 2015, with a goal of closely matching its drilling capital expenditures with cash flow from operations. In January, Lonestar set a budget of drilling 16 Eagle Ford Shale wells during 2015 at a projected cost of between $74 and $83 million, net to the Company. To date, well costs have met or been below AFE. In the second quarter, Lonestar was able to reduce average total well costs by 20% versus 4Q14 levels, and continues to make progress towards additional reductions. The schedule below reflects the 16 wells Lonestar currently plans to drill and complete in 2015, 2 of which it expects to complete in late 2015 that should see first production in 2016, as well as 3 wells which were drilled and completed in 2014 and turned to production in early 2015.

• 1Q15 – The Company fracked 3 wells (Gerke #1H, #2H, #3H) in La Salle County and turned to production

mid 1Q15. • 2Q15 – The company fracked 3 wells in on the Burns Ranch (93.3% WI) in La Salle County and began

flowback in May 2015. Following execution of a second farm-in, Lonestar drilled 3 wells (50% WI) in Southern Gonzales County near its Harvey Johnson wells. Lonestar completed fracture stimulation operations on these 3 wells in June 2015 and began flowback in mid-June 2015.

• 3Q15 – The Company completed 3 short laterals at Beall Ranch (97.7% WI) (#26H, #27H, #28H) and fracture stimulated these wells in July. The wells began production in July 2015. The Company completed two 8,000’ laterals at Horned Frog (100% WI) (A#1H & B#1H) in La Salle County, which were fracked in August and commenced flowback in September.



January 7, 2016

• 4Q15 – The Company has drilled the Pirate M#1H and N#1H in Wilson County. With production rates running ahead of budget and the Company keenly focused on matching capital spending and cash flow, Lonestar has deferred the fracture stimulation of the Pirate wells. Lonestar is currently drilling two wells on its Horned Frog acreage (15% WI) (D#1H & E#1H). The company also currently plans to spud two 8,000’ laterals in Brazos County, most likely on its Wildcat area, where the Eagle Ford lies at a TVD of 9,500 feet.

While its 2016 budget will be confirmed at the Company’s December 2015 meeting of its Board of Directors, Lonestar’s preliminary plans would be to complete 14 to 16 Eagle Ford Shale wells at a budget of $70 to $80 million.

Hedge Position Lonestar continues to be an active participant in the commodity derivatives market as a tool to manage commodity price risk, create higher certainty of returns on capital expenditures, and maximize its borrowings available under its Credit Facilities. As the Company places new wells into production, it has historically entered into additional derivatives transactions to further insulate the Company from the risks associated with the oil and gas business, and to lock in attractive returns, a policy that Lonestar expects to continue. As has been its practice since inception, crude oil hedging has been a key element to providing visibility to its cash flow streams and associated liquidity in the current crude oil price environment. In an effort to provide additional long-term visibility to its cash flow streams in the current crude oil price environment, Lonestar has recently increased its crude oil hedge position. Giving effect for these new hedges, the Company has increased its positions, and currently stand at:

• 2015 – Lonestar has West Texas Intermediate (WTI) swaps covering 2,551 barrels of oil per day for the fourth quarter of 2015 at an average strike price of $82.23 per barrel, equating to 60 to 64% of oil production guidance.

• 2016 – Lonestar has added additional WTI swaps to increase the total to 2,276 barrels of oil per day for 2016 at an average strike price of $77.15 per barrel, equating to 51 to 57% of currently budgeted oil production.

• 2017 – Lonestar’s 2017 oil hedge position consists of a 3-Way WTI Collar covering 1,000 barrels per day for calendar 2017, comprising of a $60.00/$40.00 put spread against an $85.00 call.


Lonestar Resources (LNREF)Net Income and Cash Flow 2013 - 2017 (last updated 1/7/2016)

Actual Actual Actual Forecast Forecast Forecast ForecastActual Actual Qtr1 Qtr2 Qtr3 Qtr4 Year Year Year2013 2014 2015 2015 2015 2015 2015 2016 2017

REVENUES: Oil and gas sales $81,197 $116,528 $18.4 23.5 $21.4 $27.3 $91 $124.9 $152.1 < Forecast revenues include the effect of hedging. Hedge Gains - cash -1,840 1,217 10.7 7.4 8.8 0.0 26.9 0.0 0.0 Hedging impact is broken out on rows 9 & 30

when actuals are reported. Total revenues 79,357 117,745 29.1 30.9 30.2 27.3 117.5 124.9 152.1

EXPENSES: Lease operating expenses 13,819 17,530 3.7 5.0 4.8 5.0 18.5 23.4 26.3 < $8.00/boe Production taxes 3,789 5,425 0.9 1.0 1.0 1.1 4.0 5.6 6.8 < 4.5% of Oil & Gas Revenues Ad valorum taxes 1,238 1,701 0.5 0.4 0.4 0.4 1.7 2.4 2.8 DD&A 28,280 40,723 12.8 13.3 13.0 13.8 52.9 64.4 69.0 < $22.00 / boe Impairment 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 G&A 7,534 8,913 2.3 2.4 2.4 2.6 9.7 11.0 12.5

TOTAL EXPENSES 54,660 74,292 20.2 22.1 21.6 22.9 86.8 106.9 117.4

OPERATING EARNING 24,697 43,453 8.9 8.8 8.6 4.5 30.8 18.0 34.7

OTHER INCOME (EXPENSE) Other income 10,752 55 (0.7) 0.0 0.0 0.0 (0.7) 0.0 0.0 Development expenses written off -2,762 -5,478 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Stock based compensation -2,245 -1,938 (0.4) (0.5) (0.8) (0.8) (2.5) (2.0) (2.4) < non-cash expense Interest and other finance expenses -3,744 -19,950 (5.8) (6.0) (6.7) (7.0) (25.5) (30.0) (34.0) Fair value gain (loss) on derivaties -992 42,756 (3.8) (14.9) 10.7 0.0 (8.0) 0.0 0.0 < Non-cash gains & losses on hedges are shown in "Cash Foreign exchange differences 432 -404 Flows from Investing Activities" on the consolidated

statement of cash flow. They are included in cash flows from operations below, consistant with other

INCOME BERORE INCOME TAXES 26,138 58,494 (1.8) (12.6) 11.8 (3.3) (5.9) (14.0) (1.7) forecast models.

INCOME TAXES Current -364 0 0.0 1.2 0.0 0.0 1.2 0.0 0.0 Deferred -4,570 22,432 (1.1) (5.4) 4.4 (1.2) (3.3) (5.0) (0.6) < 36%

NET INCOME $31,072 $36,062 (0.7) (8.4) 7.4 (2.1) (3.8) (8.9) (1.1)

Common Stock outstanding 710,878 753,481 15,044 15,044 15,044 15,044 15,044 15,044 15,044 < Thousand of share after 1:50 reverse split in May 2015Earnings per share $0.04 $0.05 ($0.05) ($0.56) $0.49 ($0.14) ($0.25) ($0.59) ($0.07) < EPSNOTE: Current First Call Estimated EPS $0.04 ($0.02) $0.04 N/A < First Call EPS Forecasts

$46,519 $62,307 $15.0 $17.6 $14.6 $11.2 $58.4 $52.5 $69.7 < 2015 CapEx Budget is $74 to $83 millionCashflow per share (before CapEx) $0.07 $0.08 $1.00 $1.17 $0.97 $0.75 $3.88 $3.49 $4.63 < CFPS

Fair Value Price 3 X 2015 to 2017 CFPS = $12.00PRODUCTION First Call >>> 8.19$ Natural Gas (mcfp/d) 4,368 4,664 5,770 5,909 6,863 7,800 6,586 8,400 9,600 Oil (bbls/d) 2,024 3,267 4,043 4,175 4,631 4,600 4,362 5,500 6,000 NGLs (bbls/d) 268 436 542 644 840 900 732 1,100 1,400

boepd 3,020 4,480 5,547 5,804 6,615 6,800 6,191 8,000 9,000 < Guidance for 2015 is 6,100 to 6,300PRODUCT PRICES 38.2% 29.2% 12.5% < Production Growth Natural Gas ($/mcf) 4.15 4.50 2.78 2.44 2.67 2.50 2.60 2.65 3.00 Oil ($/bbl) 96.95 87.41 74.10 75.66 64.93 58.00 68.17 55.00 60.00 NGLs ($/bbl) 29.78 29.26 14.64 14.40 11.52 12.00 13.14 15.00 20.00

Gross Revenue check (prod * ave price) 81,152 116,550 29,121 30,901 30,240 27,333 117,594 124,901 152,13228,160 108,140 119,480 N/A < First Call Revenue Forecasts

Forecast commodity prices include impact of hedges

All $ amounts in millions after 2014


January 7, 2016

Lonestar Resources, Ltd. - energyprospectus.com · 1/7/2016 · Lonestar Resources, Ltd. January...

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