Lonestar Resources Ltd. (LNREF: OTCQX International) | Lonestar Resources, Ltd. Provides Q4 2014 Financial and Operational Results


FORT WORTH, Texas, Feb. 1, 2015 /PRNewswire/ — Lonestar Resources, Ltd. (ASX:LNR, OTCQX: LNREF) is pleased to provide an update on its financial and operational results for the three months ended December 31, 2014 (4Q14).

Fourth Quarter Highlights

  • Setting a new Company record, Lonestar reported a 54% increase in net oil and gas production to 5,816 BOEPD in 4Q14, vs. 3,772 BOEPD in 4Q13, 87% of which was crude oil and NGL’s. Lonestar’s 4Q14 sales volumes also represented a 25% sequential increase over 3Q14 production levels.
  • Net Revenues From Ordinary Activities increased 41% to US$35.5 million for 4Q14, vs. 4Q13 revenues of $25.1 million.
  • EBITDAX increased 46% to $27.3 million for 4Q14 vs. $18.7 million for 4Q13, and rose 43% sequentially over 3Q14 levels, in spite of a 25% sequential decline in oil prices. Full year 2014 EBITDAX was $86.6 million, an increase of 60% over 2013 levels, and despite a precipitous fall in crude oil prices late in the year exceeded the low end of our $85 to $88 million guidance, thanks to excellent performance of new wells, notably in our Central Region.
  • Net income was $25.4 million for 4Q14, or $0.03 per share vs. net income of $4.5 million reported for 4Q13. Net of the effect of the unrealized gain on the Company’s hedges and impairment of assets, net income was $14.1 million, or $0.02 per share.
  • Based on the results generated from our independent consultants 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. The PV-10 of Lonestar’s Proved Reserves increased to US$705.8 million represents an increase of 65% over 2013 levels. For a full discussion of our reserves, please refer to our press release issued today.
  • After observing commodity price movements and taking stock of energy service costs, Lonestar is updating its 2015 guidance. Based on a price range of $50 to $60 per barrel for West Texas Intermediate and the expectation for the Company to drill 15 gross wells in 2015, Lonestar currently forecasts production levels to average between 5,700 and 6,100 BOE per day, which leads to EBITDAX guidance of $84 to $95 million for 2015.

Management’s Discussion and Analysis

Lonestar Resources, Ltd. is pleased to announce its operational and unaudited financial results for the quarter ended December 31, 2014.


Lonestar Resources, Ltd. (“Lonestar” or the “Company”) is listed on the Australian Securities Exchange (ASX) and the OTCQX in the United States, and is headquartered in Fort Worth, Texas. Lonestar Resources is focused on the acquisition, development and production of unconventional resources in the United States. Alongside optimizing cash flows from its Conventional assets, Lonestar is focusing its attention and capital to continuing its growth strategy in the crude oil window of the Eagle Ford Shale. Lonestar currently operates 100% of its 30,306 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 though 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.



  • Lonestar set its third consecutive set of record operating metrics in 2014. A strong fourth quarter placed full-year production volumes at an average of 4,480 BOEPD, an increase of 48% over 2013 levels. 2014 also saw the Company generate record levels of EBITDAX, totaling $86.6 million, representing an increase of 60% over 2013 results. These strong financial results are underpinned by a 70% increase in Lonestar’s Proved Reserves, which grew to 31.0 MMBOE at December 31, 2014, according to its third-party engineering reports. It is notable that these reserves represent a 21% increase over the Company’s pro-forma Proved Reserves of 25.6 MMBOE, which account for its acquisition of Eagle Ford Shale properties from Clayton Williams, which closed on March 13, 2014. For full disclosure regarding the Company’s third party reserves, please refer to our press release issued today.
  • Lonestar’s senior lending group, led by Wells Fargo, confirmed a 38% increase in the borrowing base on our Senior Secured Credit Facility from $108.8 million to $150.0 million, providing the Company with in excess of $100 million of liquidity at year-end 2014.


  • Lonestar’s net production for the fourth quarter of 2014 set its second consecutive record, averaging 5,816 BOE per day. Fourth quarter 2014 volumes were comprised of 4,312 barrels of oil per day, 538 barrels of NGL’s per day, and 5,796 Mcf of natural gas per day. 4Q14 production was 54% higher than 4Q13 levels. Fourth quarter production was comprised of 83% crude oil and natural gas liquids, and 17% natural gas. Of equal importance was the significant sequential production gains that were achieved- a gain of 25% over third quarter 2014 volumes.
  • In the fourth quarter of 2014, Lonestar generated Discretionary Cash Flow of $22.1 million, a 19% increase over third quarter Discretionary Cash Flow of $18.5 million.
  • As it scales its business, Lonestar continues to generate significant improvement in total unit cash operating expenses in the Eagle Ford Shale, which it believes will help insulate the Company from lower crude oil prices. Total cash unit operating expenses in the Eagle Ford Shale were reduced sequentially by 19%, from $29.17 per BOE in 3Q14 to $23.77 per BOE in 4Q14, as absolute costs were contained and production volumes were increased.
    • Lease Operating Expense was reduced 24% sequentially. In the third quarter of 2014, Lonestar’s Eagle Ford Shale assets recorded LOE of $3.1 million, or $8.44 per BOE, at the time a record-low. Benefitting from cost control measures in its Western Region and the addition of low-cost producers in its Eastern and Central Regions, 4Q14 LOE actually decreased marginally in absolute dollar terms to $3.0 million, which equates to a record-low $6.47 per BOE.
    • Production Taxes fell 31% sequentially. Owing to a combination of lower crude oil prices and lower percentage tax rates on a higher mix of crude oil, production taxes fell from $4.52 per BOE in 3Q14 to $3.12 per BOE in 4Q14.
    • General Administrative Expense decreased 13% sequentially. Lonestar’s General Administrative Expense was $2.4 million, or $4.44 per BOE in 4Q14, which represents a 13% reduction compared to 3Q14 levels of $5.09 per BOE.
    • Interest Expense fell 12% sequentially. Lonestar’s Interest Expense was $5.2 million in 3Q14, or $9.74 per BOE, which represents a 39% reduction compared to 3Q14 levels of $11.12 per BOE.
  • In an effort to provide additional long-term visibility to its cash flow streams and associated liquidity 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 West Texas Intermediate (WTI) swaps covering 2,496 barrels of oil per day for calendar 2015 at an average strike price of $88.00 per barrel and WTI swaps covering 1,905 barrels of oil per day for calendar 2016 at an average strike price of $80.00 per barrel.

Operations Review


  • Asherton– In central Dimmit County, no new wells were completed during the quarter. However, Lonestar has made considerable progress in stabilizing operating costs at Asherton. In 4Q14, Lease Operating Expenses were $0.3 million, or $6.91 per BOE, flat with the third quarter. The Asherton leasehold is Held by Production, and Lonestar has not planned drilling activity here in 2015. 
  • Beall RanchIn Dimmit and La Salle Counties, no new wells were completed during the quarter. However, Lonestar has made considerable progress in reducing operating costs at Beall Ranch, achieving a 35% reduction in unit costs over the past two quarters. In 4Q14, Lease Operating Expenses were $1.2 million, or $6.82 per BOE, compared to $1.5 million, or $10.50 per BOE in 2Q14. Lonestar currently plans to drill 3 short laterals at Beall Ranch in the fourth quarter of 2015.
  • Burns Ranch AreaIn La Salle County, Lonestar completed 3 wells on its Meiners lease, in which it holds an 85.0% WI and a 63.7% NRI. The initial test rates and the 30-day Max rates were disclosed in our third quarter report. These wells contributed fully to the Company’s fourth quarter production results. On a neighboring lease, which was acquired during the course of 2014, Lonestar drilled and completed the Gerke #1H, #2H and #3H with a 100.0% WI and a 75.0% NRI during the fourth quarter. The Company elected to defer the fracture stimulation of these wells until January, 2015 based on its view that it could obtain more favorable pressure pumping pricing at that time. The Company is pleased to announced that all three wells have been fracture stimulated with an average of 1,610 pounds of sand per perforated foot utilizing tighter stage spacing and a modified proppant slate than it has used in this area thus far. Lonestar estimates that the completed well costs for the Gerke wells will average $4.9 million per well, which is a significant savings when compared to the neighboring Meiners wells. Lonestar anticipates turning the Gerke wells to flowback within the next 7 days. During the quarter, Lonestar was able to execute a trade with another company that gives it a higher working interest in the Lonestar-operated Asherton property in exchange for its interest in the non-operated Centavo property. The exchange also delivered to Lonestar an additional 217 gross / 145 net acres in the Burns Ranch. This acreage is part of the unit on which the Company is currently drilling three 8,000-foot Eagle Ford Shale laterals. The Company anticipates fracture stimulating these wells in March, 2015.


  • Pirate Area- In southwest Wilson County, Lonestar is pleased to announce that it has added acreage that is contiguous to its existing leasehold. The Company leased under primary term an additional 576 gross/ 576 net acres. The lease bonus was $1,875 per net mineral acre, and importantly, changed the Company’s leasehold geometry so as to allow the addition of 3 long laterals to the Company’s inventory. Lonestar currently plans to drill two 7,000-foot laterals in the Pirate Area during 2015.
  • Southern Gonzales CountyDuring the fourth quarter, Lonestar has drilled and completed 3 wells in Southern Gonzales County. On or around December 1, 2014, the Company placed the Harvey Johnson #1H, #2H #3H into flowback. The wells had an average lateral length of 6,371 feet at an average TVD of 9,710 feet, and an average completed well cost of $6.8 million. To date, these are the deepest Eagle Ford laterals drilled by the Company. Lonestar paid 58% of the completed well costs to earn a 50.0% Working Interest and a 37.5% NRI in these wells. These wells, which were fracked with an average proppant concentration of 1,600 pounds per foot, have now been onstream for 60 days, and are outperforming the Type Curve issued by our third party engineers. Lonestar is sufficiently encouraged by its initial success that it plans to drill three more wells on acreage that is immediately contiguous to its initial wells. These wells have been designated Proved Undeveloped in its 2014 reserve report. Based on its best and most current assessment of energy service costs, Lonestar believes that it will be able to achieve reductions of at least $1.0 million per well (adjusted for length) on these next three wells, which are currently planned to be 5,800-foot laterals. Based on these successes, Lonestar is actively pursuing additional leasehold in southern Gonzales County.


  • Brazos Robertson Counties – In Southern Robertson County, Lonestar has drilled and completed the Dunn #A-1H with a perforated interval of 5,720 feet. Lonestar also drilled and completed the Dunn #A-2H with a perforated interval of 5,995 feet. These wells were completed at an average cost of $6.3 million, which included substantial costs associated with drilling a pilot hole and obtaining extensive advanced formation characterization logs.  The Dunn wells, which were pad drilled and zipper fracked, tested at a per-well average of 649 bopd and 192 Mcfgpd, or 693 BOEPD on a processed three-stream basis.  The two wells registered Max-30 production rates of 353 bopd and 126 Mcfgpd, or 382 BOEPD, on a 16/64″ choke.  In Brazos County, Lonestar placed the Scasta #3H onstream in early November at a completed well costs of $4.8 million. The well has a perforated interval of 4,537 feet, and was stimulated with 1,511 pounds of proppant per foot. The well tested at a rate of 337 bopd and 65 Mcfgpd, equating to a processed three-stream rate of 352 BOEPD on a 16/64″ choke.  Lonestar currently plans to drill two 8,000-foot laterals in Brazos County in 2015. These wells are currently scheduled to be drilled in the Carter Lake area, offsetting acreage where Apache recently has placed an estimated 10 wells into production, and has an additional 20 permits filed to drill offsetting wells with the Texas Railroad Commission.


  • Poplar West, MontanaBased 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 May, 2014, Lonestar submitted the application for the establishment of the Stone Turtle Indian Exploratory unit to the Bureau of Land Management (BLM) and Bureau of Indian Affairs (BIA), covering 52,559 gross acres and expects to receive approval imminently.  As currently contemplated, formation of the unit would establish a 5-year primary term on all leasehold in the unit, in exchange for drilling activity. Lonestar believes it has strong support for future development from all governmental regulatory agencies including the BIA, BLM and the Fort Peck Tribe.  Lonestar and its partners have commenced a process to farm-out a portion of their interest in Poplar West.


While the Company continues to monitor returns in light of evolving oil prices and energy service costs, 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.  After making an initial assessment of its liquidity at Strip prices and its ability to obtain cost reductions from its energy services providers, Lonestar has set a budget of 15 Eagle Ford Shale wells during 2015.  Presently, Lonestar expects its 2015 Eagle Ford Shale drilling and completion program to cost between $74 and $83 million, net to the Company.  The schedule below reflects the 15 wells Lonestar will drill and complete in 2015, 15 of which will be turned to production during the calendar year, with 3 wells which were drilled and completed in 2014 being fracked in early 2015, while 3 wells it expects to drill and complete in late 2015 are not expected to be fracked and turned to production until early 2016.  The Company continues to emphasize that it has very few obligation wells in 2015, and as opportunities present themselves to access higher return projects or farm-ins, Lonestar has the flexibility to alter its drilling plans without increasing capital outlays.

  • 1Q15The Company has fracked 3 wells (Gerke #1H, #2H, #3H) in La Salle County and will turn to production mid 1Q15. Lonestar is currently drilling three 8,000′ laterals in La Salle County.
  • 2Q15 Based on its ability to execute a second farm-in, Lonestar plans to drill 3 wells in Southern Gonzales County near its recent Harvey Johnson wells. Lonestar will hold a 50.0% WI / 37.5% NRI in these wells.
  • 3Q15Lonestar currently plans to drill two 8,000′ laterals in La Salle County in the Greater Burns Ranch area. The Company also currently plans to drill two 7,500′ laterals in Wilson County near the Pirate K 1H and L3H wells drilled in 2014.
  • 4Q15Lonestar currently plans to drill two 8,000′ laterals in Brazos County, most likely in its Carter Lake area, where the Eagle Ford lies at a TVD of 9,500 feet. The Company also plans to drill and complete 3 wells on its Beall Ranch property. These well are planned to be fracked and turned to production in 1Q16.

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SOURCE Lonestar Resources, Ltd.

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