– 3Q 2018 production of 34,750 Boe per day, up 45% from 2Q –
– 3Q 2018 oil production of 15,740 Bbl per day, up 47% from 2Q –
– 3Q 2018 Adjusted EBITDA expected to nearly double from 2Q –
DENVER, Oct. 11, 2018 (GLOBE NEWSWIRE) — Resolute Energy Corporation (“Resolute” or the “Company”) (NYSE: REN) today provided preliminary third quarter 2018 production results and an operations update.
Aggregate third quarter 2018 production averaged approximately 34,750 barrel of oil equivalent (“Boe”) per day, an increase of 45 percent from the second quarter. Third quarter 2018 oil production averaged approximately 15,740 barrels of oil per day, an increase of approximately 47 percent over second quarter 2018. Year over year, third quarter Boe production increased 54 percent and oil production increased approximately 40 percent, both pro forma for the divestiture of the Aneth Field assets. Growth in production is being driven by the Company’s successful ongoing development program. During the quarter, the Company spud six wells, reached total depth on thirteen wells and placed eighteen wells on production.
Third quarter 2018 net loss is expected to increase compared to the second quarter net loss of $3.7 million due in large part to the effect of non-cash mark-to-market derivative losses. Third quarter 2018 Adjusted EBITDA is expected to be nearly double second quarter 2018 Adjusted EBITDA of $33.7 million (a non-GAAP measure as defined and reconciled below). This significant increase in expected Adjusted EBIDTA is being driven by stronger production volumes, as well as lower unit operating and overhead costs.
Our third quarter 2018 cost structure is expected to have improved substantially from second quarter as a result of lower per unit lease operating expense and cash-based general and administrative expense, primarily due to significantly higher production volumes with only moderately higher absolute operating costs and modestly lower cash general and administrative expenses from quarter to quarter.
Based on the strong results from our drilling program, the borrowing base under the Company’s revolving credit facility was increased nearly 50% from $210 million to $310 million. This $100 million increase ensures that we will continue to have sufficient liquidity to prosecute our business plan. At September 30, 2018, the Company had approximately $200 million of availability under the revolving credit facility.
Rick Betz, Resolute’s Chief Executive Officer, said: “As expected, our 2018 development program has begun to pay dividends in the form of significantly increased production and cash flow. Having now finished drilling four multi-well pads, we have advanced our understanding of how to execute these large capital programs and are collecting the technical data that will help us continue to improve the productivity of our assets. As with other producers making the shift to multi-well pad drilling in the Basin, we learn more about the reservoir and subsurface interactions with every well we drill. Additionally, through a period of intense infrastructure challenges, our midstream arrangements have served us well as we continue to move product to end markets with no significant curtailments and continue to dispose of significant quantities of produced water at advantageous rates. As we close out the 2018 program and look forward to 2019, we remain committed to a pad-based development program that grows production while spending within cash flow.”
Resolute’s Board of Directors, in conjunction with its financial advisors, has continued to monitor the Company’s competitive positioning in the Permian Basin in light of the improving industry conditions, the strong macroeconomic backdrop and recent transactional activity. As part of its ongoing effort to maximize stockholder value, the Board continues to evaluate all alternatives available to the Company, including potential strategic combinations, while the Company continues its Delaware Basin drilling program.
The Company has completed drilling operations on 32 of the 42 wells included in our 2018 development program. These wells are in four individual well packs, two of which are in the Appaloosa area (the Ranger nine-well pack and the South Mitre eight-well pack) and two of which are in the Mustang area (both nine-well packs in the Sandlot unit). The Company has finished completion operations on 28 wells so far this year including 21 of the 32 new drills, six DUCs carried over from 2017 (three wells in the Ranger nine pack and three Lower Wolfcamp wells), and one recompletion associated with the South Mitre well pack in Appaloosa. Completion operations will begin in mid-October on the second Sandlot nine pack, bringing our completions in 2018 to 37 total wells. We anticipate these Sandlot wells will be placed on production in November.
As anticipated, the Company’s pad-focused drilling and completion activity has resulted in significant growth in both production and cash flow in the third quarter, with oil production increasing 47% from the second quarter of 2018 and Adjusted EBITDA anticipated to grow by nearly 100%. We anticipate the Company will see significant growth in oil production and cash flow in the fourth quarter, although at a less robust rate than the third quarter as fewer new wells will be placed on production and those wells will come on later in the quarter.
While oil production increased 47% from the second quarter, we also saw strong growth in gas and natural gas liquids during the period, which resulted in an overall product mix that was similar to what we experienced in the second quarter. Total production measured in barrels equivalent reflects a growth rate consistent with previously provided guidance, although the percentage of oil in our third quarter production is approximately five points below that guidance, primarily influenced by strong Mustang production. We anticipate that over the longer term, our production will be approximately 50% oil as operational activity is more balanced among our various operating areas.
The expectation that oil would represent a higher proportion of third quarter production was partially based on anticipated performance from the Ranger nine pack that was placed on production late in the first quarter of 2018. Located in Appaloosa, these wells generally have higher oil cuts, in the range of 58-60% for the Wolfcamp A, than other areas of the field, materially influencing both the aggregate level of oil production and the oil component of total production. The three UWCA wells and the WCC well in this well pack have shown performance consistent with our expectations from a total production as well as an oil cut perspective. However, while oil cut from the three LWCA and two UWCB wells is consistent with our expectations, total production from these wells has underperformed our expectations, leading to lower aggregate oil production for the quarter. The table below presents production rates for this well pack.
|Average peak rate
|Appaloosa Ranger nine-pack results||Wolfcamp zones1||Average length (feet)||First
Boe per day
Boe per day
Boe per day
|Average cumulative oil to date|
|Ranger||UWCA (3)||9,647||5/30 – 6/4||2,377||2,315||2,152||60%|
|Ranger||LWCA (3)||9,593||5/25 – 5/28||2,550||2,229||1,908||59%|
|Ranger||UWCB (2)||9,667||6/7 – 6/8||2,070||1,798||1,551||52%|
|Ranger C205SL||WCC (1)||9,721||5/24||1,990||1,822||1,699||44%|
|1. Zone abbreviation legend: UWCA – Upper Wolfcamp A; LWCA – Lower Wolfcamp A; UWCB – Upper Wolfcamp B; WCC – Wolfcamp C|
Based on the extensive data gathering and analytics, including microseismic analysis of the completions, tracer analysis during flowback, real time rock property data gathered during drilling and downhole pressure measurement, we have identified modifications which we are implementing in our drilling elsewhere in the field and which we believe should improve future well performance, particularly in the LWCA and the UWCB zones. The most significant change has been to widen the vertical spacing between the wells by adjusting landing zones for the lower wells to increase the stimulated rock volume within the well pack. As noted below we are testing this modified spacing in both the South Mitre well pack in Appaloosa and the second Sandlot nine pack in Mustang. We will evaluate any impact these changes may have on our overall inventory as we gather more data.
Third quarter production volumes and composition were also influenced by the Company’s second nine-well pack in the Sandlot unit in Mustang, which was brought on production in mid-July. Along with strong oil production, Mustang wells typically produce at higher gas and NGL rates than wells drilled in Appaloosa. The Sandlot nine-well group consists of three UWCA wells, three LWCA wells and three UWCB wells, with average completed lateral lengths of approximately 6,200 feet. The table below presents initial production rates for this well pack.
|Average peak rate|
|Mustang Sandlot nine-pack results||Wolfcamp
Boe per day
Boe per day
|Average cumulative oil to date|
|Sandlot||UWCA (3)||6,280||7/7 – 7/11||2,112||1,880||49%|
|Sandlot||LWCA (3)||5,860||7/7 – 7/11||3,050||2,491||41%|
|Sandlot||UWCB (3)||6,373||7/7 – 7/12||2,844||2,336||33%|
|1. Zone abbreviation legend: UWCA – Upper Wolfcamp A; LWCA – Lower Wolfcamp A; UWCB – Upper Wolfcamp B|
The Sandlot well pack was drilled using the same vertical spacing as the Ranger well pack. Overall these wells are performing close to expectations, and the well pack has exhibited a lesser degree of the relative performance differences between the UWCA and the LWCA and UWCB wells experienced in the Ranger wells.
In late September, the Company brought online the South Mitre well pack. This well pack includes three UWCA wells, two LWCA wells and three UWCB wells. The ninth well in this pack is a LWCA well originally completed in July 2016. In order to gauge the potential benefits of wider vertical spacing in Appaloosa, for now the Company has left the two LWCA wells uncompleted while watching the interactions among the remaining wells during completion using microseismic data and evaluating the production response of the UWCA and UWCB wells. The six wells that have been completed have an average completed lateral length of approximately 9,684 feet. Two weeks into their flowback, the wells are producing more than 4,700 Boe per day (58% cumulative oil) in aggregate as of the date of this release, and have not yet reached peak rates. The Company will gather production data from these wells and the Ranger nine-pack over the next few months to assist in our ongoing process of determining the optimal vertical spacing in Appaloosa. Deferring completion of the two LWCA wells in South Mitre unit will impact the Company’s fourth quarter production somewhat. That impact is reflected in the updated 2018 guidance provided below.
The Company recently finished drilling operations on the fourth nine-pack, located in the Sandlot unit in Mustang. The second Sandlot well pack was drilled using wider vertical spacing. In particular, the UWCB wells were drilled lower in the section than previous UWCB landing zones. We anticipate that this approach will result in improved well performance for both the LWCA and UWCB wells. The Company will gather and evaluate production data from these wells and the first Sandlot nine-pack to assist in determining the optimal vertical spacing in Mustang.
Consistent with our previously announced schedule, we released one of our three drilling rigs at the conclusion of drilling operations on the second Sandlot nine-pack. In order to provide time to analyze recently acquired 3D seismic covering the Appaloosa area as well as the impact on well performance of adjusted vertical well spacing, we have elected to defer the drilling of the next Appaloosa well pack and will employ the two remaining drilling rigs to first drill four Mustang wells targeting Lower Wolfcamp zones that will be completed in early 2019. These four wells include one LWCB well and three WCC wells.
After finishing drilling operations on these four Lower Wolfcamp wells in Mustang, we currently anticipate the rigs will move to the third well pack in the Sandlot unit in late November, with all of the wells to be completed in 2019.
Through the first four well packs in the 2018 program, we anticipate that drilling and completions capital expense will be substantially in line with our original budget. Facilities capital for these well packs has run somewhat higher than plan due to the need to handle higher than anticipated gas and water volumes. Overall for the year, after adjustments to the development plan noted above, we expect total capital to be below the midpoint of our original guidance range.
Updated Guidance Summary
Based on results through the third quarter and expectations for the remainder of the year, we are providing updated full year 2018 guidance as follows.
|Projected 2018 production|
|Annual production (MBoe)||10,950 – 12,045||10,950 – 11,680|
|Annual average Boe per day||30,000 – 33,000||30,000 – 32,000|
|Annual oil percent||49% – 50%||45%|
|Annual oil and NGL percent||75%||72%|
|Projected full year 2018 costs ($ million)|
|Cash lease operating expense||$60 – $68||$64 – $67|
|Cash general and administrative expense1||$30 – $34||$31 – $33|
|Projected full year 2018 capital expenditures ($ million)2||$365 – $395||$370 – $380|
|1. Net of COPAS reimbursements and capitalization, before one-time costs associated with the Aneth Field sale and stockholder activism expenses.|
|2. Net of earnout payments of approximately $23 million expected to be received from Caprock Midstream and not including $10 million of contingent purchase price payable from the purchaser of Aneth Field.|
Reconciliation of Non-GAAP Measures
In this press release, the term “Adjusted EBITDA” is used. Adjusted EBITDA is a non-GAAP financial measure defined as consolidated net income (loss) adjusted to exclude interest expense, net, income taxes, depletion, depreciation and amortization expenses, one-time costs of the Aneth Field sale, costs related to stockholder activism, non-cash stock-based compensation expense, nonrecurring cash-settled incentive award payments, change in fair value of derivative instruments, gains and losses on the sale of assets and ceiling write-down of oil and gas properties. Resolute’s management believes Adjusted EBITDA is an important financial measurement tool that facilitates comparison of our operating performance and provides information about the Company’s ability to service or incur indebtedness and pay for its capital expenditures. This information differs from measures of performance determined in accordance with GAAP and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. This measure is not necessarily indicative of operating profit or cash flow from operating activities as determined under GAAP and may not be equivalent to similarly titled measures of other companies. The table below reconciles Resolute’s net income (loss) to Adjusted EBITDA.
|Three Months Ended
|($ in thousands)
|Interest expense, net||8,515|
|Depletion, depreciation, and amortization||23,494|
|Cash-settled incentive awards||(47||)|
|Cash-settled incentive awards paid||(1,219||)|
|Contingent consideration gain||(3,703||)|