Attached files
| file | filename |
|---|---|
| EX-99.2 - EXHIBIT 99.2 - Lonestar Resources US Inc. | a2q18presentation.htm |
| 8-K - 8-K - Lonestar Resources US Inc. | a8-kxq2earningsreleaseands.htm |
Lonestar Announces Second Quarter 2018 Financial Results
And Provides Operational Update
Fort Worth, Texas, August 5, 2018 (PRNewswire) - Lonestar Resources US Inc. (NASDAQ: LONE) (including its subsidiaries, “Lonestar,” “we,” “us,” “our” or the “Company”) today reported financial and operating results for the three months ended June 30, 2018.
HIGHLIGHTS
• | Lonestar reported a record production result with a 98% increase in net oil and gas production to 11,140 Boe/d during the three months ended June 30, 2018 (“2Q18”), compared to 5,635 Boe/d for the three months ended June 30, 2017 (“2Q17”). Production volumes exceeded the high end of the Company’s guidance of 10,000 - 10,500 Boe/d, and were 79% crude oil and NGL’s on an equivalent basis. The increase in production was attributable to continued excellence in our drilling and completion program that has seen greater-than-expected well productivity at our Hawkeye, Horned Frog and Karnes properties in the Eagle Ford Shale. |
• | Benefitting from continued outperformance in production results and good visibility on new well startups, Lonestar issued production guidance of 11,750-12,200 Boe/d for the third quarter of 2018 (”3Q18”). The midpoint of this guidance represents an 8% sequential increase over 2Q18 results and is 57% higher than production reported for the three months ended September 30, 2017 (“3Q17”). It is also important to note that the forecasted oil mix increases from 57% in 2Q18 to 61% in 3Q18 as Lonestar begins to bring on the oiliest part of its 2018 drilling program. Lonestar also issued guidance for 3Q18 Adjusted EBITDAX of $32 to $34 million, which represents a 13% sequential improvement at its midpoint, and a 63% increase over 3Q17 results. |
• | Based on continued outperformance in well results across its portfolio and that fact that we have outperformed our targeted improvement in debt metrics, Lonestar has elected to increase its 2018 capital program to bring 21 gross wells onstream, versus 19 gross wells previously. Consequently, Lonestar has increased its drilling and completion budget from a range of $110 - $115 million to a range of $120 - $130 million. To account for continued outperformance of its 2018 program and the addition of 2 wells which will contribute for a portion of the fourth quarter of 2018, Lonestar is again increasing its full-year 2018 production guidance from 10,300-11,000 Boe/d to a range of 10,600-11,200 Boe/d, which equates to a 68% increase over 2017 results. Commensurately, Lonestar has also increased its 2018 EBITDAX guidance from a range of $110-$125 million to a range of $115-$130 million, based on a $60 average WTI oil price for the remainder of 2018. |
1
• | Lonestar reported a net loss attributable to its common stockholders of $20.7 million, or ($0.84) per weighted average share, during 2Q18 compared to a net loss of $23.5 million, or ($1.07) per weighted average share during the 2Q17. Excluding, on a tax-adjusted basis, certain items that the Company does not view as either recurring or indicative of its ongoing financial performance, Lonestar’s adjusted net loss for 2Q18 was $3.5 million, or ($0.14) per common share. Most notable among these items include: unrealized hedging losses on financial derivatives, stock-based compensation and non-recurring legal expenses. Please see Non-GAAP Financial Measures for additional information. |
• | Lonestar reported a 131% increase in Adjusted EBITDAX for the three months ended June 30, 2018 of $29.2 million compared to $12.7 million for 2Q17, which exceeded our guidance of $27.0 - $29.0 million and is a Company record. This improvement was driven by a 98% increase in production and a 5% increase in the Company’s oil-equivalent price realization after the effect of hedging. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted EBITDAX, a reconciliation of net loss to Adjusted EBITDAX, and the reasons for its use. |
• | The visibility provided by a continuous drilling and completion program provides the Company with the confidence to issue a preliminary 2019 Outlook. Based on a drilling and completion budget of $120-$130 million, Lonestar sees daily production increasing to a range of 13,000 -14,000 Boe/d in 2019 and Adjusted EBITDAX increasing to a range of $140-$160 million. Importantly, this 2019 program can be executed with a single rig and can be essentially funded by internally generated cash flow. |
Lonestar’s Chief Executive Officer, Frank D. Bracken, III, stated, “In the second quarter, we achieved a production increase of 98% and a 131% increase in Adjusted EBITDAX. Our record-setting second quarter results also represent sharp sequential improvements of 43% for production and 25% for Adjusted EBITDAX. Our second quarter results begin to more fully reflect the outstanding drilling results we have generated thus far in 2018 and have generated operating metrics which continue to exceed guidance. Equally important to Lonestar’s improved outlook is the considerable progress we have made in improving our debt metrics and liquidity. Since 2Q17, we have reduced Debt / EBITDAX (Last Quarter Annualized) from 5.4x to 2.8x in 2Q18”
Bracken further remarked, “Our momentum in the Eagle Ford Shale continues to build, and our technical, operational and financial achievements are delivering high price realizations, high margins and outstanding returns to our shareholders, giving us the confidence to augment our 2018 drilling and completion program. Not only can the expanded 2018 program be executed with drilling, completion and fracture stimulation equipment currently under contract, but extending that program deeper into 2018 provides seamless transition into our 2019 program. The visibility provided by a continuous drilling and completion program gives us the confidence to issue a preliminary 2019 Outlook, which sees production increasing by 24% over 2018 levels and Adjusted EBITDAX increasing by a similar amount. Importantly, this 2019 program can be executed with a single rig and can be essentially funded by internally generated cash flow.”
OPERATIONAL UPDATE
• | Lonestar reported net oil and gas production of 11,140 Boe/d during the three months ended June 30, 2018, an increase of 98% compared to 5,635 Boe/d during the three months ended June 30, 2017. 2Q18 production volumes consisted of 6,378 barrels of oil per day (57%), 2,438 barrels of NGLs |
2
per day (22%), and 13,943 Mcf of natural gas per day (21%). The Company’s production mix for the three months ended June 30, 2018 was 79% liquid hydrocarbons.
• | Lonestar’s Eagle Ford Shale assets delivered excellent wellhead realizations in 2Q18. Lonestar’s realized wellhead crude oil price was $68.41 per barrel, which reflects a positive differential of $0.47/bbl vs. West Texas Intermediate. Lonestar’s realized NGL price was $19.88 per barrel in the second quarter of 2018. Lonestar’s natural realized wellhead natural gas price was $2.94 per Mcf, which reflects a positive differential of $0.11 to the Henry Hub. |
• | Lonestar has delivered a significant reduction in cash operating costs in 2Q18. Total Cash Operating Expenses for the three months ended June 30, 2018 were $20.3 million, which was 48% higher than cash operating expenses of $13.7 million in the three months ended June 30, 2017. On a unit-of-production basis, cash operating expenses decreased 25% from $26.72 per Boe in the three months ended June 30, 2017 to $20.01 per Boe in the three months ended June 30, 2018. |
• | Lease Operating Expenses (“LOE”) for the three months ended June 30, 2018 were $5.7 million, which was 77% higher than Lease Operating Expenses of $3.2 million in the three months ended June 30, 2017, but was outpaced by a 98% increase in production. On a unit-of-production basis, lease operating expenses decreased 18% to $5.62 per Boe for the three months ended June 30, 2018. On a sequential basis, Lonestar reduced lease operating expenses per Boe by 5% to $5.62. For 2018, the Company expects LOE to be between $5.60 and $6.50 per Boe, as relatively fixed costs are spread over substantially larger production volumes. |
• | Gathering, Processing & Transportation Expenses (“G,P&T”) for the three months ended June 30, 2018 were $0.8 million, which was 157% higher than the G,P&T of $0.3 million in the three months ended June 30, 2017, but commensurate with a 183% increase in gas production. On a unit-of-production basis, G,P&T increased 30% to $0.79 per Boe for the three months ended June 30, 2018. For 2018, the Company expects G,P&T expense to average between $0.75 and $0.85 per Boe. |
• | Production Taxes for the three months ended June 30, 2018 were $2.8 million, which was 156% higher than production taxes of $1.1 million in the three months ended June 30, 2017, driven largely by a 164% increase in wellhead oil and gas revenues. On a unit-of-production basis, production taxes increased 30% to $2.72 per Boe for the three months ended June 30, 2018. |
• | General & Administrative Expenses, excluding stock-based compensation of $0.5 million in the three months ended June 30, 2017 and $2.3 million in the three months ended June 30, 2018 (“G&A”), decreased from $3.1 million to $3.0 million, respectively. On a unit-of-production basis, G&A per Boe was reduced 51% year over year, from $6.12 per Boe in 2017 to $2.98 per Boe in 2018. For 2018, the Company expects G&A to average between $2.80 and $3.00 per Boe. |
• | Interest Expense excluding amortization of debt issuance cost, premiums, and discounts increased year over year from $6.0 million in the three months ended June 30, 2017 to $8.3 million in 2018. This was primarily due to a combination of higher stated interest rates and principal on the new 11.25% Senior Notes versus the 8.75% Senior Notes that were retired |
3
in January 2018. On a unit-of-production basis, interest per Boe decreased 30% year over year from $11.64 per Boe in 2017 to $8.15 per Boe in 2018. For 2018, the Company expects interest expense to average between $8.15 and $8.75 per Boe.
• | In the second quarter of 2018, Lonestar expanded its Eagle Ford operations, placing 5.0 gross / 4.4 net wells online, which included its first wells at Georg in Karnes County (3.0 gross / 2.4 net) and first wells at its Horned Frog NW property in La Salle County (2.0 gross / 2.0 net). Results at these locations have exceeded third party estimates, with initial production rates (“IP’s”) on the Georg wells coming in at greater than 1,200 Boepd and Horned Frog NW greater than 1,100 Boepd. In the third quarter, Lonestar plans to increase completion activity, placing 8.0 gross / 6.8 net wells online. This includes 2.0 gross / 2.0 net wells at Cyclone placed into flowback in July, 3.0 gross / 2.4 net wells at Georg during the month of August and 3.0 gross / 2.4 net wells at Culpepper during the month of September. |
EAGLE FORD SHALE TREND- WESTERN REGION
Asherton – In July 2018, Lonestar commenced drilling the Asherton #1H and Asherton #3H with planned total measured depths of approximately 17,680 feet. We project that these wells will have perforated intervals of approximately 10,800 feet. Drilling operations are underway and fracture stimulation operations are scheduled for October 2018. Lonestar owns a 99% working interest (“WI”) and 75% Net Revenue Interest (“NRI”) in these two wells.
Beall Ranch – In Dimmit County, no new wells were completed during the three months ended June 30, 2018. The Beall Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.
Burns Ranch Area – At the Burns Ranch leasehold in La Salle County, no new wells were completed during the three months ended June 30, 2018. The Burns Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here as part of its 2018 drilling and completion budget.
Horned Frog – In La Salle County, the Company further expanded its Eagle Ford Shale footprint by completing its first two locations at Horned Frog North West. The Horned Frog North West #2H and #3H commenced flowback operations in June, 2018. Results of these wells have been encouraging and have a substantially higher oil mix (+125% per foot) than the legacy Horned Frog acreage located to the South. The #2H and #3H wells were drilled to measured depths of 17,560 feet and 17,440 feet, respectively and were fracture-stimulated in engineered completions with an average proppant concentration of 2,030 pounds per foot across an average of 25 stages per well utilizing diverters. The Horned Frog NW #2H, which has a perforated interval of 7,489 feet, continues to be choke-managed, and produced at a Max 30-day production rate of 1,110 Boe/d, consisting of 573 barrels of oil per day, 185 barrels of natural gas liquids per day, and 2,113 Mcf/d of natural gas on a 22/64” choke. The Horned Frog NW #3H, which has a perforated interval of 7,331 feet, continues to be choke-managed, and produced at a Max 30-day production rate of 1,050 Boe/d, consisting of 551 barrels of oil per day, 172 barrels of natural gas liquids per day, and 1,964 Mcf/d of natural gas. Both of these wells are outperforming internal projections, particularly with respect to higher-than-expected oil rates. Lonestar holds a 100% WI and 75% NRI in these wells and has an additional 5 drilling locations offsetting these wells.
4
Lonestar owns a 100% WI in the Horned Frog G #1H and Horned Frog H #1H, which were placed onstream in March 2018. These wells have now been producing for in excess of four months and the results continue to outperform projections. After registering Max-30 IP’s averaging 2,155 Boe/d, these wells continue to exhibit robust deliverability on a constant choke. During the first 120 days of production, the Horned Frog G #1H has produced cumulative production of 47,820 barrels of oil and 818,390 Mcf of natural gas, or 240,975 barrels of oil equivalent on a three-stream basis, an average of 2,008 Boe/d over its first 120 days of production. Over the same period, the Horned Frog H #1H has produced cumulative production of 44,235 barrels of oil and 753,898 Mcf of natural gas, or 222,171 barrels of oil equivalent on a three-stream basis, an average of 1,865 Boe/d over its first 120 days of production. To date, these are the two highest producing wells through the first 120 days of production in the Company’s history and have outperformed third-party projections by 15%.
EAGLE FORD SHALE TREND- CENTRAL REGION
Cyclone – In July 2018, the Company completed drilling operations on the Cyclone DM #13H and Cyclone DM #14H to total measured depths of 20,205 feet and 19,685 feet, respectively. The Cyclone DM #13H and #14H wells were fracture-stimulated in engineered completions with an average proppant concentration of 1,590 pounds per foot over 35 stages and 34 stages, respectively. The Cyclone DM #13H was completed with a perforated interval of 10,056 feet and tested 577 Bbls/d of oil and 329 Mcf/d of natural gas, or 652 Boe/d (three-stream) on a 28/64’’ choke. The Cyclone DM #14H was completed with a perforated interval of 9,600 feet and tested 635 Bbls/d of oil and 362 Mcf/d of natural gas, or 718 Boe/d (three-stream) on a 28/64’’ choke. Lonestar owns a 100% WI and 78.5% NRI in these wells.
Hawkeye – Lonestar owns an 87.5% WI in the Hawkeye #1H and Hawkeye #2H, which were placed onstream in January 2018. In May, these wells were put on artificial lift which actually increased production by an average of 17% vs. the prior 30 day period. The Hawkeye wells have continued to break away from forecast, outperforming third-party projections by 23%. Now online for 180 days, the Hawkeye #1H has produced a cumulative 115,800 barrels of oil and 63,517 Mcf of natural gas, or 130,356 barrels of oil equivalent on a three-stream basis, or an average of 727 Boe/d over its first 180 days of production. Over the same period, the Hawkeye #2H has produced a cumulative 99,335 barrels of oil and 53,615 Mcf of natural gas, or 111,620 barrels of oil equivalent on a three-stream basis, or an average of 617 Boe/d. The Company continues to grow its leasehold position in the Hawkeye area, having recently acquired approximately 976 gross / 976 net acres which is contiguous to our existing leasehold, which can accommodate 7 additional locations. Lonestar plans to drill two laterals on this newly acquired leasehold which are projected to average approximately 8,700’ of perforated interval. We expect to place these wells onstream in November, 2018.
Karnes County – In May 2018, Lonestar completed the Georg EF #18H, Georg EF #19H, and Georg EF #20H to an average total measured depth of 15,450 feet. The Georg EF #18H, which has a perforated interval of 5,896 feet, produced at a Max 30-day production rate of 895 Boe/d, consisting of 775 barrels of oil per day, 64 barrels of natural gas liquids per day, and 336 Mcf per day of natural gas. The Georg EF #19H, which has a perforated interval of 6,116 feet, produced at a Max 30-day production rate of 898 Boe/d, consisting of 781 barrels of oil per day, 62 barrels of natural gas liquids per day, and 327 Mcf per day of natural gas. The Georg EF #20H, which has a perforated interval of 5,979 feet, produced at a Max 30-day production rate of 1,052 Boe/d, consisting of 925 barrels of oil per day, 68 barrels of natural gas liquids per day, and 356 Mcf per day of natural gas. Lonestar owns an 80% WI and 61%
5
NRI in these wells. To date, these wells have outperformed the projections of our independent petroleum engineer.
Pirate – In Wilson County, no new wells were completed during the three months ended June 30, 2018. The Pirate leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.
Current Operations – Lonestar plans to bring six more wells in the Central Region onstream during the third quarter of 2018. In Karnes County, the Georg #24H, Georg #25H, and Georg #26H have total measured depths of 15,450 feet, 15,500 feet and 15,495 feet, respectively. Fracture stimulation operations have been completed and these wells are expected to begin flowback operations in mid-August. Lonestar owns an 80% WI and 61% NRI in these wells. In Gonzales County, the Culpepper #3-2H, Culpepper #3-3H, and Culpepper #4-4H, which were also drilled on leasehold obtained in the Battlecat acquisition, were drilled to total measured depths of 15,380 feet, 15,325 feet and 15,280 feet, respectively. Fracture stimulation is set to begin in August and flowback operations are forecast to begin in mid-September. Lonestar owns an 80% WI and 60% NRI in these wells.
EAGLE FORD SHALE TREND- EASTERN REGION
Brazos & Robertson Counties – In Brazos County, no new wells were completed during the three months ended June 30, 2018. Lonestar is currently discussing drilling one well on our partners leasehold. Lonestar does not currently have drilling activity budgeted here in 2018.
CONFERENCE CALL DETAILS
Lonestar will host a live conference call on Monday, August 6, 2018 at 9:00 AM CDT to discuss the second quarter 2018 results and operational highlights.
To access the conference call, participants should dial:
USA: 877-256-5083
International: +1-303-223-4391
A playback of the conference call will be available on the Investor Relations section of Company’s website beginning approximately August 7, 2018. The playback will be available for approximately 2 weeks.
6
ABOUT LONESTAR RESOURCES US INC.
Lonestar is 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 accumulated approximately 80,944 gross (60,037 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of June 30, 2018. For more information, please visit www.lonestarresources.com.
CAUTIONARY & FORWARD LOOKING STATEMENTS
Lonestar Resources US Inc. cautions that this press release contains forward-looking statements, including, but not limited to; Lonestar’s execution of its growth strategies; growth in Lonestar’s leasehold, reserves and asset value; and Lonestar’s ability to create shareholder value. These statements involve substantial known and unknown risks, uncertainties and other important factors that may cause our actual results, levels of activity, performance or achievements to be materially different from the information expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, the following: volatility of oil, natural gas and NGL prices, and potential write-down of the carrying values of crude oil and natural gas properties; inability to successfully replace proved producing reserves; substantial capital expenditures required for exploration, development and exploitation projects; potential liabilities resulting from operating hazards, natural disasters or other interruptions; risks related using the latest available horizontal drilling and completion techniques; uncertainties tied to lengthy period of development of identified drilling locations; unexpected delays and cost overrun related to the development of estimated proved undeveloped reserves; concentration risk related to properties, which are located primarily in the Eagle Ford Shale of South Texas; loss of lease on undeveloped leasehold acreage that may result from lack of development or commercialization; inaccuracies in assumptions made in estimating proved reserves; our limited control over activities in properties Lonestar does not operate; potential inconsistency between the present value of future net revenues from our proved reserves and the current market value of our estimated oil and natural gas reserves; risks related to derivative activities; losses resulting from title deficiencies; risks related to health, safety and environmental laws and regulations; additional regulation of hydraulic fracturing; reduced demand for crude oil, natural gas and NGLs resulting from conservation measures and technological advances; inability to acquire adequate supplies of water for our drilling operations or to dispose of or recycle the used water economically and in an environmentally safe manner; climate change laws and regulations restricting emissions of “greenhouse gases” that may increase operating costs and reduce demand for the crude oil and natural gas; fluctuations in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price actual crude oil and natural gas sales; and the other important factors discussed under the caption “Risk Factors” in our on our Annual Report on Form 10-K filed with the Securities and Exchange Commission, or the SEC, on March 29, 2018 our Quarterly Reports on Form 10-Q filed with the SEC, as well as other documents that we may file from time to time with the SEC. We may not actually achieve the plans, intentions or expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Actual results or events could differ materially from the plans, intentions and expectations disclosed in the forward-looking statements we make. The forward-looking statements in this press release represent our views as of the date of this press release. We anticipate that subsequent events and developments will cause our views to change. However, while we may elect to update these forward-looking statements at some point in the future, we have no current intention of doing so except to the extent required by applicable law. You should,
7
therefore, not rely on these forward-looking statements as representing our views as of any date subsequent to the date of this press release.
(Financial Statements to Follow)
8
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
June 30, 2018 | December 31, 2017 | ||||||||
Assets | |||||||||
Current assets | |||||||||
Cash and cash equivalents | $ | 5,460 | $ | 2,538 | |||||
Accounts receivable | |||||||||
Oil, natural gas liquid and natural gas sales | 12,041 | 12,289 | |||||||
Joint interest owners and others, net | 1,396 | 794 | |||||||
Related parties | 62 | 162 | |||||||
Derivative financial instruments | 145 | 472 | |||||||
Prepaid expenses and other | 1,653 | 2,365 | |||||||
Total current assets | 20,757 | 18,620 | |||||||
Property and equipment | |||||||||
Oil and gas properties, using the successful efforts method of accounting | |||||||||
Proved properties | 834,493 | 750,226 | |||||||
Unproved properties | 76,619 | 78,655 | |||||||
Other property and equipment | 16,817 | 15,763 | |||||||
Less accumulated depletion, depreciation, amortization | (294,049 | ) | (259,382 | ) | |||||
Net property and equipment | 633,880 | 585,262 | |||||||
Other non-current assets | 2,086 | 2,918 | |||||||
Total assets | $ | 656,723 | $ | 606,800 | |||||
Liabilities and Stockholders' Equity | |||||||||
Current liabilities | |||||||||
Accounts payable | $ | 32,086 | $ | 25,901 | |||||
Accounts payable -- related parties | 270 | 389 | |||||||
Oil, natural gas liquid and natural gas sales payable | 11,254 | 8,747 | |||||||
Accrued liabilities | 31,519 | 16,583 | |||||||
Derivative financial instruments | 27,570 | 12,336 | |||||||
Total current liabilities | 102,699 | 63,956 | |||||||
Long-term liabilities | |||||||||
Long-term debt | 337,264 | 301,155 | |||||||
Asset retirement obligations | 5,918 | 5,649 | |||||||
Deferred tax liabilities, net | 106 | 8,105 | |||||||
Equity warrant liability | 1,404 | 508 | |||||||
Equity warrant liability -- related parties | 2,682 | 963 | |||||||
Derivative financial instruments | 22,186 | 9,802 | |||||||
Other non-current liabilities | 4,948 | 1,316 | |||||||
Total long-term liabilities | 374,508 | 327,498 | |||||||
Commitments and contingencies | |||||||||
Stockholders' Equity | |||||||||
Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 24,637,127 and 24,506,647 issued and outstanding, respectively | 142,655 | 142,655 | |||||||
Class B non-voting common stock, $0.001 par value, 5,000 shares authorized, 2,500 shares issued and outstanding | — | — | |||||||
Series A-1 convertible participating preferred stock, $0.001 par value, 87,789 and 83,968 shares issued and outstanding, respectively | — | — | |||||||
Additional paid-in capital | 174,469 | 174,871 | |||||||
Accumulated deficit | (137,608 | ) | (102,180 | ) | |||||
Total stockholders' equity | 179,516 | 215,346 | |||||||
Total liabilities and stockholders' equity | $ | 656,723 | $ | 606,800 | |||||
9
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||||||
Revenues | |||||||||||||||||||
Oil sales | $ | 39,707 | $ | 15,090 | $ | 72,859 | $ | 29,580 | |||||||||||
Natural gas liquid sales | 4,410 | 1,319 | 6,143 | 2,989 | |||||||||||||||
Natural gas sales | 3,735 | 1,726 | 5,542 | 3,182 | |||||||||||||||
Total revenues | 47,852 | 18,135 | 84,544 | 35,751 | |||||||||||||||
Expenses | |||||||||||||||||||
Lease operating and gas gathering | 6,490 | 3,521 | 11,074 | 6,477 | |||||||||||||||
Production and ad valorem taxes | 2,761 | 1,077 | 4,927 | 2,114 | |||||||||||||||
Depreciation, depletion and amortization | 19,464 | 12,551 | 35,027 | 24,693 | |||||||||||||||
Loss on sale of oil and gas properties | — | 205 | 1,568 | 348 | |||||||||||||||
Impairment of oil and gas properties | — | 27,081 | — | 27,081 | |||||||||||||||
General and administrative | 5,305 | 3,600 | 8,724 | 6,281 | |||||||||||||||
Acquisition costs and other | (3 | ) | 2,680 | (13 | ) | 2,669 | |||||||||||||
Total expenses | 34,017 | 50,715 | 61,307 | 69,663 | |||||||||||||||
Income (loss) from operations | 13,835 | (32,580 | ) | 23,237 | (33,912 | ) | |||||||||||||
Other (expense) income | |||||||||||||||||||
Interest expense | (9,298 | ) | (8,819 | ) | (18,555 | ) | (13,851 | ) | |||||||||||
Unrealized (loss) gain on warrants | (2,462 | ) | 614 | (2,615 | ) | 2,884 | |||||||||||||
(Loss) gain on derivative financial instruments | (25,498 | ) | 5,416 | (36,654 | ) | 14,162 | |||||||||||||
Loss on extinguishment of debt | — | — | (8,619 | ) | — | ||||||||||||||
Total other (expense) income, net | (37,258 | ) | (2,789 | ) | (66,443 | ) | 3,195 | ||||||||||||
Loss before income taxes | (23,423 | ) | (35,369 | ) | (43,206 | ) | (30,717 | ) | |||||||||||
Income tax benefit | 4,648 | 12,208 | 7,778 | 10,621 | |||||||||||||||
Net loss | (18,775 | ) | (23,161 | ) | (35,428 | ) | (20,096 | ) | |||||||||||
Preferred stock dividends | (1,932 | ) | (296 | ) | (3,821 | ) | (296 | ) | |||||||||||
Net loss attributable to common stockholders | $ | (20,707 | ) | $ | (23,457 | ) | $ | (39,249 | ) | $ | (20,392 | ) | |||||||
Net loss per common share | |||||||||||||||||||
Basic | $ | (0.84 | ) | $ | (1.07 | ) | $ | (1.60 | ) | $ | (0.93 | ) | |||||||
Diluted | $ | (0.84 | ) | $ | (1.07 | ) | $ | (1.60 | ) | $ | (0.93 | ) | |||||||
Weighted average common shares outstanding | |||||||||||||||||||
Basic | 24,599,744 | 21,822,015 | 24,598,345 | 21,822,015 | |||||||||||||||
Diluted | 24,599,744 | 21,822,015 | 24,598,345 | 21,822,015 | |||||||||||||||
10
Lonestar Resources US Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
Three Months Ended June 30, | Three Months Ended June 30, | ||||||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||||||
Cash flows from operating activities | |||||||||||||||||||
Net loss | $ | (18,775 | ) | $ | (23,163 | ) | $ | (35,428 | ) | $ | (20,096 | ) | |||||||
Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||||||||||||||
Depreciation, depletion and amortization | 19,463 | 12,551 | 35,027 | 24,693 | |||||||||||||||
Stock-based compensation | 2,263 | 461 | 2,713 | 639 | |||||||||||||||
Share-based payments | 9 | — | (601 | ) | — | ||||||||||||||
Deferred taxes | (4,785 | ) | (12,576 | ) | (7,999 | ) | (10,985 | ) | |||||||||||
Loss (gain) on derivative financial instruments | 25,464 | (5,416 | ) | 36,620 | (14,162 | ) | |||||||||||||
Settlements of derivative financial instruments | (5,560 | ) | 1,167 | (8,676 | ) | 2,682 | |||||||||||||
Impairment of oil and gas properties | — | 27,081 | — | 27,081 | |||||||||||||||
Loss on abandoned property and equipment | — | — | 170 | — | |||||||||||||||
Non-cash interest expense | 1,067 | 2,854 | 3,544 | 3,434 | |||||||||||||||
Unrealized loss (gain) on warrants | 2,463 | (613 | ) | 2,615 | (2,884 | ) | |||||||||||||
Changes in operating assets and liabilities: | |||||||||||||||||||
Accounts receivable | (122 | ) | 802 | (254 | ) | (1,308 | ) | ||||||||||||
Prepaid expenses and other assets | (450 | ) | (2,632 | ) | (1,159 | ) | (3,010 | ) | |||||||||||
Accounts payable and accrued expenses | 7,869 | 3,861 | 12,179 | 11,028 | |||||||||||||||
Net cash provided by operating activities | 28,906 | 4,377 | 38,751 | 17,112 | |||||||||||||||
Cash flows from investing activities | |||||||||||||||||||
Acquisition of oil and gas properties | (1,257 | ) | (106,615 | ) | (2,862 | ) | (108,179 | ) | |||||||||||
Development of oil and gas properties | (35,238 | ) | (18,908 | ) | (66,761 | ) | (37,750 | ) | |||||||||||
Purchases of other property and equipment | (150 | ) | (1,509 | ) | (1,498 | ) | (1,522 | ) | |||||||||||
Net cash used in investing activities | (36,645 | ) | (127,032 | ) | (71,121 | ) | (147,451 | ) | |||||||||||
Cash flows from financing activities | |||||||||||||||||||
Proceeds from borrowings and related party borrowings | 26,178 | 67,079 | 290,744 | 76,079 | |||||||||||||||
Payments on borrowings and related party borrowings | (15,017 | ) | (17,003 | ) | (255,452 | ) | (19,503 | ) | |||||||||||
Proceeds from sale of preferred stock | — | 77,800 | — | 77,800 | |||||||||||||||
Cost to issue equity | — | — | — | (1,000 | ) | ||||||||||||||
Payments of debt issuance costs | — | (2,537 | ) | — | (2,537 | ) | |||||||||||||
Net cash provided by financing activities | 11,161 | 125,339 | 35,292 | 130,839 | |||||||||||||||
Net decrease in cash and cash equivalents | 3,422 | 2,684 | 2,922 | 500 | |||||||||||||||
Cash and cash equivalents, beginning of the period | 2,038 | 3,884 | 2,538 | 6,068 | |||||||||||||||
Cash and cash equivalents, end of the period | $ | 5,460 | $ | 6,568 | $ | 5,460 | $ | 6,568 | |||||||||||
Supplemental information: | |||||||||||||||||||
Cash paid for taxes | $ | — | $ | 2,240 | $ | 1,147 | $ | 2,240 | |||||||||||
Cash paid for interest | 2,173 | 9,762 | 6,143 | 10,674 | |||||||||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Preferred stock issued for asset acquisition | $ | — | $ | 10,795 | $ | — | $ | 10,795 | |||||||||||
Cost to issue equity included in accounts payable | — | 1,500 | — | 1,500 | |||||||||||||||
Asset retirement obligation | 151 | 2,323 | 183 | 2,235 | |||||||||||||||
Increase (decrease) in liabilities for capital expenditures | 12,019 | (4,203 | ) | 12,425 | 1,358 | ||||||||||||||
11
NON-GAAP FINANCIAL MEASURES (Unaudited)
Reconciliation of Non-GAAP Financial Measures
Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as net (loss) income before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, (gain) loss on sales of oil and natural gas properties, impairment of oil and gas properties, stock-based compensation, interest expense, income tax (benefit) expense, rig standby expense, other income (expense) and unrealized (gain) loss on derivative financial instruments and unrealized (gain) loss on warrants.
Management believes Adjusted EBITDAX provides useful information to investors because it assists investors in the evaluation of the Company’s operating performance and comparison of the results of the Company’s operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at Adjusted EBITDAX to eliminate the impact of certain non-cash items or because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. The Company’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net loss for each of the periods indicated.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||
($ in thousands) | 2018 | 2017 | 2018 | 2017 | ||||||||||||||||
Net Loss | $ | (20,707) | $ | (23,457) | $ | (39,249) | $ | (20,392) | ||||||||||||
Income tax benefit | (4,648) | (12,208) | (7,778) | (10,621) | ||||||||||||||||
Interest expense (1) | 11,230 | 9,115 | 22,376 | 14,147 | ||||||||||||||||
Exploration expense | — | 205 | — | 205 | ||||||||||||||||
Depreciation, depletion and amortization | 19,464 | 12,551 | 35,027 | 24,693 | ||||||||||||||||
EBITDAX | 5,339 | (13,794) | 10,376 | 8,032 | ||||||||||||||||
Non-recurring costs (2) | — | 3,127 | — | 3,127 | ||||||||||||||||
Stock-based compensation | 2,281 | 461 | 2,731 | 639 | ||||||||||||||||
Loss on sale of oil and gas properties | — | 205 | — | 348 | ||||||||||||||||
Impairment of oil and gas properties | — | 27,081 | — | 27,081 | ||||||||||||||||
Unrealized loss (gain) on derivative financial instruments | 18,896 | (3,770 | ) | 26,489 | (12,109 | ) | ||||||||||||||
Unrealized loss (gain) on warrants | 2,462 | (613 | ) | 2,615 | (2,884 | ) | ||||||||||||||
Lease write-off | — | — | 1,568 | — | ||||||||||||||||
Loss on extinguishment of debt | — | — | 8,619 | — | ||||||||||||||||
Other expense (income) | 232 | (46 | ) | 226 | (50 | ) | ||||||||||||||
Adjusted EBITDAX | 29,210 | 12,651 | 52,624 | 24,184 | ||||||||||||||||
1 Interest expense also includes dividends paid on Series A Preferred Stock
2 Non-recurring costs consists of Acquisitions Costs and General and Administrative Expenses related to the re-domiciliation to the United States, and listing on NASDAQ
12
Adjusted Loss
Adjusted net income comparable to analysts’ estimates as set forth in this release represents income or loss from operations before income taxes adjusted for certain non-cash items (detailed in the accompanying table) less income taxes. We believe adjusted net income comparable to analysts’ estimates is calculated on the same basis as analysts’ estimates and that many investors use this published research in making investment decisions and evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Diluted earnings per share (adjusted) as set forth in this release represents adjusted net income comparable to analysts’ estimates on a diluted per share basis. A table is included which reconciles income or loss from operations to adjusted net income comparable to analysts’ estimates and diluted earnings per share (adjusted).
The following table presents a reconciliation of Adjusted Net Income to the GAAP financial measure of net loss for each of the periods indicated.
Lonestar Resources US Inc.
Unaudited Reconciliation of Loss Before Income Taxes As Reported To Loss Before Income Taxes Excluding Certain Items, a non-GAAP measure (Adjusted Loss)
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||||||||||
(In thousands) | (In thousands) | ||||||||||||||||||||||
Loss before income taxes, as reported | $ | (23,423 | ) | $ | (35,369 | ) | $ | (43,206 | ) | $ | (30,717 | ) | |||||||||||
Adjustments for special items: | |||||||||||||||||||||||
Impairment of oil and gas properties | — | 27,081 | — | 27,081 | |||||||||||||||||||
Early payment premium on Second Lien Notes | — | 1,050 | — | 1,050 | |||||||||||||||||||
Warrant discount recognition due to early payment on Second Lien Notes | — | 1,991 | — | 1,991 | |||||||||||||||||||
Legal expenses for corporate governance and public reporting setup | — | 399 | — | 399 | |||||||||||||||||||
General & administrative non-recurring costs | 1 | 205 | 8 | 212 | |||||||||||||||||||
Non-recurring legal expense | 233 | — | 233 | — | |||||||||||||||||||
Loss on extinguishment of debt | — | — | 8,619 | — | |||||||||||||||||||
Unrealized hedging (gain) loss | 18,896 | (3,770 | ) | 26,489 | (12,109 | ) | |||||||||||||||||
Lease write-off | — | — | 1,568 | — | |||||||||||||||||||
Stock based compensation | 2,281 | 461 | 2,731 | 639 | |||||||||||||||||||
Advisory fees for completion of acquisition | — | 2,726 | — | 2,726 | |||||||||||||||||||
Loss before income taxes, as adjusted | $ | (2,012 | ) | $ | (5,226 | ) | $ | (3,558 | ) | $ | (8,728 | ) | |||||||||||
Income tax benefit (expense), as adjusted | |||||||||||||||||||||||
Current | — | — | — | — | |||||||||||||||||||
Deferred (a) | 415 | 1,815 | 735 | 3,031 | |||||||||||||||||||
Net loss excluding certain items, a non-GAAP measure | $ | (1,597 | ) | $ | (3,411 | ) | $ | (2,823 | ) | $ | (5,697 | ) | |||||||||||
Preferred stock dividends | (1,932 | ) | (296 | ) | (3,821 | ) | (296 | ) | |||||||||||||||
Net loss after preferred dividends excluding certain items, a non-GAAP measure | $ | (3,529 | ) | $ | (3,707 | ) | $ | (6,644 | ) | $ | (5,993 | ) | |||||||||||
Non-GAAP loss per common share | |||||||||||||||||||||||
Basic | $ | (0.14 | ) | $ | (0.17 | ) | $ | (0.27 | ) | $ | (0.27 | ) | |||||||||||
Diluted | $ | (0.14 | ) | $ | (0.17 | ) | $ | (0.27 | ) | $ | (0.27 | ) | |||||||||||
Non-GAAP diluted shares outstanding, if dilutive | 24,559,744 | 21,822,015 | 24,598,345 | 21,822,015 | |||||||||||||||||||
(a) | Effective tax rate for 2018 and 2017 is estimated to be approximately 21% and 35%, respectively. |
13
Lonestar Resources US Inc.
Unaudited Operating Results
In thousands, except per share and unit data | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
Operating revenues | ||||||||||||||||
Oil | $ | 39,707 | $ | 15,090 | $ | 72,859 | $ | 29,580 | ||||||||
NGLs | 4,410 | 1,319 | 6,143 | 2,989 | ||||||||||||
Natural gas | 3,735 | 1,726 | 5,542 | 3,182 | ||||||||||||
Total operating revenues | $ | 47,852 | $ | 18,135 | $ | 84,544 | $ | 35,751 | ||||||||
Total production volumes by product | ||||||||||||||||
Oil (Bbls) | 580,398 | 324,324 | 1,097,041 | 616,848 | ||||||||||||
NGLs (Bbls) | 221,858 | 91,364 | 308,786 | 174,846 | ||||||||||||
Natural gas (Mcf) | 1,268,813 | 582,582 | 1,848,010 | 1,170,346 | ||||||||||||
Total barrels of oil equivalent (BOE) | 1,013,740 | 512,785 | 1,713,708 | 986,812 | ||||||||||||
Daily production volumes by product | ||||||||||||||||
Oil (Bbls/d) | 6,378 | 3,564 | 6,061 | 3,408 | ||||||||||||
NGLs (Bbls/d) | 2,438 | 1,004 | 1,706 | 966 | ||||||||||||
Natural gas (Mcf/d) | 13,943 | 6,402 | 10,210 | 6,466 | ||||||||||||
Total barrels of oil equivalent (BOE/d) | 11,140 | 5,635 | 9,468 | 5,452 | ||||||||||||
Average realized prices | ||||||||||||||||
Oil ($ per Bbl) | $ | 68.41 | $ | 46.52 | $ | 66.41 | $ | 47.95 | ||||||||
NGLs ($ per Bbl) | 19.88 | 14.43 | 19.89 | 17.10 | ||||||||||||
Natural gas ($ per Mcf) | 2.94 | 2.96 | 3.00 | 2.72 | ||||||||||||
Total oil equivalent, excluding the effect from hedging ($ per BOE) | 47.20 | 35.36 | 49.33 | 36.23 | ||||||||||||
Total oil equivalent, including the effect from hedging ($ per BOE) | 40.69 | 38.57 | 43.40 | 38.31 | ||||||||||||
Operating and other expenses | ||||||||||||||||
Lease operating and gas gathering | $ | 6,490 | $ | 3,521 | $ | 11,074 | $ | 6,477 | ||||||||
Production and ad valorem taxes | 2,761 | 1,077 | 4,927 | 2,114 | ||||||||||||
Depreciation, depletion and amortization | 19,464 | 12,551 | 35,027 | 24,693 | ||||||||||||
General and administrative | 5,305 | 3,600 | 8,724 | 6,281 | ||||||||||||
Interest expense | 9,298 | 8,819 | 18,555 | 13,851 | ||||||||||||
Operating and other expenses per BOE | ||||||||||||||||
Lease operating and gas gathering | $ | 6.40 | $ | 6.87 | $ | 6.46 | $ | 6.56 | ||||||||
Production and ad valorem taxes | 2.72 | 2.10 | 2.88 | 2.14 | ||||||||||||
Depreciation, depletion and amortization | 19.20 | 24.48 | 20.44 | 25.02 | ||||||||||||
General and administrative | 5.23 | 7.02 | 5.09 | 6.36 | ||||||||||||
Interest expense | 9.17 | 17.20 | 10.83 | 14.04 | ||||||||||||
(1) | General and administrative expenses include stock-based compensation |
(2) | Interest expense includes amortization of debt issuance cost, premiums, and discounts |
14