REN Resolute Energy Corp. Comon Stock

Resolute Energy Corporation (“Resolute” or the “Company”) (NYSE: REN) today reported operating and financial results for the quarter and six months ended June 30, 2018.

Highlights:

• Second quarter 2018 Permian Basin production increased 31 percent year-over-year to 24,036 barrels of oil equivalent (“Boe”) per day from 18,383 Boe per day in second quarter 2017.
• Based on strong early production from the Company’s pad development program, second quarter 2018 exit rate production jumped to more than 35,000 Boe per day, up more than 75 percent from first quarter exit rate.
• In Appaloosa, the Company’s first nine-pack, located in the Ranger unit, came online in early June leading to strong production growth later in the second quarter and into the third quarter.
• In Mustang, the Company’s second nine-pack, located in the Sandlot unit, came online in mid-July and is currently producing more than 13,000 Boe per day and still inclining.
• In Appaloosa, by early August the Company expects to have finished drilling its third well-pack, located in the South Mitre unit; completions are expected to begin in mid-August with wells expected online in late September.
• Third quarter 2018 Permian Basin oil production is expected to increase 58 percent year-over-year and 68 percent over second quarter 2018 based on the mid-point of third quarter production guidance of 34,000 to 37,000 Boe per day.
• Mustang Lower Wolfcamp wells are significantly outperforming type curve with strong oil rates, competitive with Upper Wolfcamp in the area; this adds approximately 150 locations to development inventory.

Rick Betz, Resolute’s Chief Executive Officer, said: “Our drilling, completions and operations teams continued to make significant strides during the second quarter in advancing our Upper Wolfcamp-focused development program.  With the two initial well packs now on production, a third pack entering the completion phase, and a fourth pack about to commence drilling, the impact of this activity is just now beginning to show in the Company’s operating results. While the timing of initial production from our first pack was such that the impact was limited in the second quarter, our 35,000 Boe per day exit rate and continued strong growth already in the third quarter demonstrate the production and cash flow potential of our assets. In parallel with execution of our Upper Wolfcamp development program, Resolute’s technical team has been advancing our understanding of the Lower Wolfcamp zones. Based on results from multiple wells, we now believe it is appropriate to add approximately 150 new locations in Mustang to our current development inventory, thus extending our projected development program by several years.  The teams continue to work on the Lower Wolfcamp in Appaloosa as well as the Bone Spring intervals across our acreage and, based on early results, I expect we will be adding additional drilling inventory in the quarters to come. The evolution of Resolute in the first half of 2018 has been both challenging and exciting and we remain committed to ensuring that the program will drive significant expansion in long term stockholder value.”

The Company will post an updated investor relations presentation on www.resoluteenergy.com to supplement the information provided in this press release.

Operational Highlights

Permian Basin production increased 31 percent year-over-year to 24,036 Boe per day from 18,383 Boe per day in second quarter 2017.  Based on strong early production from the Company’s pad development program, second quarter 2018 exit rate production jumped to more than 35,000 Boe per day, up more than 75 percent from the first quarter 2018 exit rate. Third quarter 2018 Permian Basin oil production is expected to increase 58 percent year-over-year to 17,750 barrels (“Bbl”) per day based on the mid-point of guidance, from 11,227 Bbl per day in third quarter 2017. Full year 2018 Permian Basin oil production is expected to increase 51 percent year-over-year to 15,593 Bbl per day based on the mid-point of guidance, from 10,315 Bbl per day in 2017.

For the second quarter, Company production consisted of 45 percent oil, 26 percent NGL and 29 percent residue gas. For the quarter, percentage of production represented by oil was slightly lower than expected as a result of the higher-oil cut Ranger nine-pack wells coming online two weeks later than anticipated. The Company’s commodity mix varies quarter to quarter and is largely dependent on the specific wells, producing intervals and geographic area from which production is generated.  For the second quarter, production was weighted toward Mustang (52%) and Appaloosa (41%) with a smaller fraction from Bronco (7%). 

The Company brought the Ranger nine-pack online in early June. This nine-well group consists of eight Upper Wolfcamp wells and one Wolfcamp C well.  Six of these Upper Wolfcamp wells, including four Wolfcamp A wells and two Wolfcamp B wells, were drilled in locations not immediately adjacent to existing producing wells (“parent” wells).  Two additional Wolfcamp A wells were drilled immediately offsetting existing producing wells (“child” wells), which were completed in 2017.  The 24-hour peak IP rates from the six Upper Wolfcamp parent wells averaged 2,476 Boe per day, or 256 Boe per day per 1,000 feet of completed lateral. Production from these wells to date has averaged 59 percent oil.  The 24-hour peak IP rates from the two Upper Wolfcamp child wells averaged 2,034 Boe per day, or 212 Boe per day per 1,000 feet of completed lateral and exhibit similar oil cuts to the Upper Wolfcamp parent wells.  While the two child wells are exhibiting improved performance relative to some previously completed child wells, the child wells have underperformed expectations. The Company continues to be informed by observations gathered, including microseismic data, from the Ranger nine-pack completions and early production, and believes modifications to its completion design in future multi-well packs can continue to improve future child well results and further limit interference. The last well in the Ranger nine-pack was a Lower Wolfcamp well completed in the Wolfcamp C formation (see more information on this well below).

AppaloosaRanger nine-pack results		Zones1		Length(feet)		First Production		Average peak rate24 hourBoe per day		Average cumulative oil
Ranger - (six parent wells)		UA (2) / LA (2) / UB (2)		9,659		5/28 - 6/8		2,476		59%
Ranger - (two child wells)		UA (1) / LA (1)		9,601		5/25 - 5/30		2,034		60%
Ranger C205SL		WCC		9,721		5/24		1,990		48%

1. Zone abbreviation legend: UA – Upper Wolfcamp A; LA – Lower Wolfcamp A; UB – Upper Wolfcamp B; WCC – Wolfcamp C

In mid-July, the Company successfully brought online its second nine-pack, in the Sandlot unit in Mustang. This nine-well group consists of three Upper Wolfcamp A wells, three Lower Wolfcamp A wells, and three Upper Wolfcamp B wells. The wells have an average completed lateral length of approximately 6,200 feet. All three pads, each containing three wells, were completed simultaneously utilizing three completion crews. While still early, the wells are producing more than 13,000 Boe per day (44% cumulative oil) in aggregate as of the date of this release, and have not yet reached peak rates. As there were previously no producing wells in the Sandlot unit, we do not expect to experience the same child well issues experienced in the Ranger unit.

The Company expects to have finished drilling operations on the third nine-pack, located in the South Mitre unit in Appaloosa, this week and the rigs will be mobilized back to the Sandlot unit to start drilling the next well-pack. The South Mitre well-pack includes three Upper Wolfcamp A wells, two Lower Wolfcamp A wells, and three Upper Wolfcamp B wells.  The ninth well in this pack is a Lower Wolfcamp A well originally completed in July 2016. Because two of the new wells in the pattern will be adjacent to this well, the existing well will be re-fraced contemporaneously with completing the other eight wells. The Company anticipates that this approach will both mitigate the issues associated with the completion of the offsetting wells as well as limit the impact of the completions on the existing parent well. Completion operations are expected to begin by mid-August with first production from these wells expected in late September. 

The Company continues to evaluate of the Lower Wolfcamp intervals (the Lower Wolfcamp B and Wolfcamp C) in Appaloosa and Mustang.  Since Resolute’s last earnings press release, the Company has completed two additional Lower Wolfcamp wells in Appaloosa: the Ranger C205SL (Wolfcamp C) and the North Elephant B301SL (Lower Wolfcamp B). The Ranger C205SL has a current 24-hour peak IP rate of 1,990 Boe per day (46% oil), or 205 Boe per day per 1,000 feet of completed lateral and remains near peak rates on choked flow. The North Elephant B301SL has a current 24-hour peak IP rate of 1,683 Boe per day (36% oil), or 231 Boe per day per 1,000 feet of completed lateral. The Company now has six Lower Wolfcamp wells on production. 

With the accumulation of additional production data, Resolute has become more encouraged with the Lower Wolfcamp zones. In particular, the Lower Wolfcamp wells in the Mustang area have exhibited stronger oil production and lower water cuts than experienced elsewhere in the field. As of the date of this release, we had 129 and 166 days of production history in the Thunder Canyon and Uinta Wolfcamp C wells in Mustang, respectively.  These wells have produced cumulative volumes of 287 and 379 MBoe respectively including 66 and 94 MBbl of oil.  Based on this early performance we anticipate production and rates of return from these wells to be significantly above our original Wolfcamp C type curve and potentially competitive with our Upper Wolfcamp type curves in Mustang.  The success of these initial Lower Wolfcamp wells in Mustang will have the impact of moving approximately 150 locations into our development inventory thus extending our projected development program by several years at our current drilling pace. In Appaloosa, we are encouraged by early well performance and we will continue to gather additional data from recently completed wells prior to modifying our development plan for this area. 

Results of these wells are in the table below.

								Peak rates (Boe per day)
Well name		Area1		Zone2		Length (feet)		24 hour		30 day		60 day		90 day
South Elephant B307SL		A		LWCB		9,567		2,254		2,099		1,968		1,840
South Elephant C207SL		A		WCC		9,403		2,294		1,930		1,695		1,547
Uinta C101H		M		WCC		7,819		3,095		2,865		2,718		2,544
Thunder Canyon C107SL		M		WCC		7,942		3,000		2,655		2,559		2,458
Ranger C205SL		A		WCC		9,721		1,990		1,588		1,494		-
North Elephant B301SL		A		WCC		7,283		1,683		1,389		1,241		-

1. Area abbreviation legend: M – Mustang and A – Appaloosa
2. Zone abbreviation legend: LWCB – Lower Wolfcamp B and WCC – Wolfcamp C

With respect to uphole zones, the Company also has been evaluating nearby results in the Third Bone Spring. Based on our evaluations to date, we believe this zone will be prospective across a significant portion of our acreage and we anticipate testing this zone sometime in late 2018 or early 2019.

The Company expects to see strong growth in both oil and total production over the second half of 2018 and into 2019. The overall product mix is anticipated to shift slightly to 49 percent to 50 percent oil for 2018 from previous guidance of 52 percent oil.  This shift is reflective of delays in initial production from both the Ranger and Sandlot nine-packs and early well performance, particularly from the Ranger child wells, and strong rates from some of our Lower Wolfcamp wells. The Company reaffirms production guidance of 34 MBoe to 37 MBoe per day for the third quarter 2018, and 30 MBoe to 33 MBoe for the full year. The Company expects that third quarter production will average approximately 50 percent oil.  At the mid-point of guidance, the Company anticipates third quarter oil production of 1.7 million barrels, up approximately 70% from third quarter 2017 Permian oil production.  For the full year the Company expects oil production of 5.6 million barrels at the mid-point of guidance, up 51 percent from 2017 Permian oil production. 

Financial Highlights

Second quarter 2018 net loss was $5.0 million compared to net income available to common stockholders of $10.7 million in second quarter 2017. Second quarter 2018 Adjusted net loss (a non-GAAP measure as defined and reconciled below) was $1.6 million compared to Adjusted net income of $7.4 million in second quarter 2017.

Second quarter 2018 Adjusted EBITDA (a non-GAAP measure as defined and reconciled below) of $33.7 million was lower than first quarter Adjusted EBITDA by $7.4 million, primarily reflecting $1.3 million in lower oil and gas revenue based on weaker realized pricing, $2.1 million of higher derivative losses and $3.7 million higher LOE associated with initial flowback from the Ranger nine-pack and elevated workover expenses.  Third quarter Adjusted EBITDA is expected to increase significantly based on results from the Company’s pad development program.

Realized oil pricing for second quarter 2018 was $59.96 per Bbl, a decrease of two percent from first quarter 2018, driven primarily by weaker Midland benchmark pricing. Realized NGL pricing was $15.92 per Boe for second quarter 2018, an increase of three percent from first quarter 2018. Realized gas pricing for second quarter 2018 was $1.50 per MMBtu, an eighteen percent decrease from first quarter 2018, driven by lower benchmark pricing and wider gas basis in the Permian Basin.

Second quarter 2018 lease operating expense (“LOE”) was $15.4 million, or $7.02 per Boe, compared to $19.9 million, or $8.97 per Boe in second quarter 2017, due primarily to the 2017 sale of Aneth Field, which had higher operating costs. Second quarter 2018 LOE of $7.02 per Boe was up from $5.52 per Boe in first quarter 2018, due primarily to higher variable expenses associated with the early time Ranger flowback that occurred ahead of significant hydrocarbon production and higher workover expense which can vary significantly quarter to quarter. We expect unit LOE costs to be near first quarter levels in the third quarter and for the year we expect to be within our previously announced guidance range.

GAAP-based general and administrative expense as shown on the Company’s statement of operations decreased significantly in second quarter 2018 to $15.9 million from $21.1 million in the first quarter 2018. Included in this GAAP-based number for the second quarter is non-cash stock-based compensation expense of $4.5 million, down 49 percent from $8.8 million in first quarter 2018.  Also included in second quarter general and administrative expense was $3.1 million of costs associated with stockholder activism. Based on the settlement agreement with Monarch, the Company does not expect to incur any material additional activism-related expenses in 2018.

Cash-based general and administrative expense (a non-GAAP measure as defined and reconciled below), which management believes is a more accurate reflection of the costs of managing the business, was $8.3 million for second quarter 2018 compared to $8.9 million for the first quarter 2018.  On a unit basis, cash based general and administrative expense decreased to $3.79 per Boe in the second quarter 2018 from $4.22 per Boe in first quarter 2018. We expect cash-based general and administrative expense for the year to be within our previously announced guidance range.

Capital investment for the second quarter was $150.3 million, excluding acquisition, divestitures, and capitalized interest.  Second quarter capital investment included $133.2 million of drilling, completion and well facility expenditures and $9.1 million spent on facilities and infrastructure.  Preliminary cost estimates for our first nine-pack in Ranger and our first nine-pack in Sandlot indicate that the operations in aggregate were completed substantially in line with our original budget. We expect total 2018 capital outlays to be within previously announced guidance.

Resolute currently has hedges in place for approximately 63 percent of estimated crude oil production for September through December 2018 (based on the midpoint of guidance) at a weighted average floor of $56.51 per Bbl and a weighted average ceiling of $58.74 per Bbl; the Company’s 2018 crude oil hedge portfolio includes swaps and collars. For 2019, the Company recently added 5,000 Bbl per day of oil swaps at $64.54 per Bbl.

Resolute also has put various basis hedges in place. The Company has basis swaps locking in a $8.08 per Bbl Midland-Cushing differential on almost 10,000 Bbl per day, approximately 46 percent of estimated crude oil production for September through December 2018. The Company also has gas basis swaps locking in a $0.69 per MMBtu differential relative to Henry Hub on 18,000 MMBtu per day. The Company continues to actively review multiple options in the financial and physical markets to further mitigate basis differential risk.

Please refer to the table below for full details of the Company’s commodity derivative contracts.

Period		Product		Type of Contract		Volume(Bbl/day)			Volume(MMBtu/day)			Weighted AverageFloor Price			Weighted AverageCeiling Price
Aug 2018(1)		Oil		Swaps			3,000		—			$	50.56		$	—
		Oil		Collars(3)			5,500		—				52.45			57.93
		Oil		Basis Swaps (4)			6,000		—				5.61		—
		Gas		Swaps		—				20,000			2.77		—
		Gas		Basis Swaps (5)		—				18,000			0.69		—
Sep - Dec 2018(1)		Oil		Swaps			8,000		—				59.29		—
		Oil		Collars(3)			5,500		—				52.45			57.93
		Oil		Basis Swaps (4)			9,869		—				8.08		—
		Gas		Swaps		—				10,000			2.77		—
		Gas		Basis Swaps (5)		—				18,000			0.69		—
2019(2)		Oil		Swaps			5,000		—				64.54		—
		Oil		Basis Swaps (4)			5,000		—				10.37		—

1. The Company has entered into sold call options of 2,200 Bbl per day at $60.00 per Bbl and bought call options of 1,100 Bbl per day at $55.00 per Bbl.
2. The Company has entered into sold call options of 3,670 Bbl per day at $64.36 per Bbl.
3. Each of the Company's three-way collars has a sub-floor price of $40.00 per Bbl.
4. The Company has entered into oil basis swaps in order to hedge the Midland-Cushing differential.
5. The Company has entered into gas basis swaps in order to hedge the El Paso Permian differential.

As previously announced, the Company engaged Petrie Partners, LLC and Goldman Sachs & Co. LLC to assist the Board in a review of the Company’s business plan, competitive positioning, and potential strategic alternatives, including potential merger, sale or business combination. Petrie and Goldman made a presentation to the Board with their analysis at the most recent Board meeting. In the exercise of its fiduciary obligations with the goal of enhancing stockholder value, the Board will continue to actively monitor and evaluate all potential strategic alternatives as the Company pursues its highly accretive drilling program in the Delaware Basin.

Second Quarter and Six Months Comparative Results

Resolute recorded a net loss available to common stockholders of $5.0 million, or $0.22 per diluted share, on revenue of $73.4 million during the three months ended June 30, 2018.  Included in the net loss were $12.1 million of commodity derivative losses.  This compares to net income available to common stockholders of $10.7 million, or $0.47 per diluted share, on revenue of $70.3 million during the three months ended June 30, 2017.  Included in net income for 2017 were $7.5 million of commodity derivative gains.  Resolute recorded an Adjusted net loss of $1.6 million, or $0.07 per diluted share, for second quarter 2018.  This compares to Adjusted net income for the comparable prior year period of $7.4 million, or $0.32 per diluted share.

For the six months ended June 30, 2018, Resolute recorded a net loss available to common stockholders of $19.1 million, or $0.86 per diluted share, on revenue of $148.1 million.  Included in the net loss were $21.5 million of commodity derivative losses.  This compares to net income available to common stockholders of $10.8 million, or $0.47 per diluted share, on revenue of $134.9 million during the six months ended June 30, 2018.  Included in net income for 2017 were commodity derivative gains of $18.3 million.  Resolute recorded Adjusted net income of $1.7 million, or $0.07 per diluted share, for the six months ended June 30, 2018.  This compares to an Adjusted net loss for the comparable prior year period of $2.2 million, or $0.10 per diluted share.

Second Quarter and Six Months 2018 Results Compared toSecond Quarter and Six Months 2017 Results

	Three Months Ended June 30,								Six Months Ended June 30,
	2018				2017				2018				2017
	($ thousands, except per-Boe amounts)
Production (MBoe):
Permian		2,187				1,673				4,302				2,915
Aneth	—					543			—					1,074
Total production		2,187				2,216				4,302				3,989
Daily rate (Boe)		24,036				24,355				23,769				22,041
Revenue per Boe (excluding commodity derivative  settlements)	$	33.55			$	31.70			$	34.42			$	33.80
Revenue per Boe (including commodity derivative  settlements)	$	29.28			$	32.45			$	30.56			$	34.15
Revenue	$	73,380			$	70,260			$	148,098			$	134,852
Commodity derivative settlements		(9,343	)			1,656				(16,620	)			1,406
Adjusted revenue		64,037				71,916				131,478				136,258
Operating expenses:
Lease operating	$	15,366			$	19,890			$	27,031			$	38,246
Production and ad valorem taxes		5,521				5,565				11,061				11,534
Depletion, depreciation and amortization		23,494				22,333				47,031				38,368
General and administrative		15,875				9,472				36,942				19,887
Cash-settled incentive awards		(47	)			(1,413	)			11,294				4,014
Net income (loss) available to common stockholders	$	(5,002	)		$	10,690			$	(19,128	)		$	10,766
Adjusted net income (loss)	$	(1,573	)		$	7,426			$	1,691			$	(2,191
Adjusted EBITDA	$	33,667			$	38,719			$	74,742			$	71,234

Production:  Production for the quarter ended June 30, 2018, decreased one percent to 2,187 MBoe, or 24,036 Boe per day, as compared to 2,216 MBoe, or 24,355 Boe per day, during the second quarter of 2017.  The decrease from the comparable prior year period is primarily the result of the 2017 Aneth Field Sale, offset by production from newly drilled and completed wells in the Delaware Basin. Pro forma for the 2017 Aneth Field Sale, second quarter 2018 production increased 31 percent.

During the first half of 2018, production increased eight percent to 4,302 MBoe, or 23,769 Boe per day, from 3,989 MBoe, or 22,041 Boe per day, during the first half of 2017.  The increases from the comparable prior year period are primarily the result of production from newly drilled and completed wells in the Delaware Basin. Pro forma for the Aneth Field Sale, production increased 48 percent.

Revenue:  During the second quarter 2018, Resolute realized a four percent increase in revenue as compared to the prior year quarter primarily attributable to increased commodity pricing.  Revenue for the quarter was $73.4 million as compared to $70.3 million in the prior year period.  Resolute realized an eleven percent decrease in Adjusted revenue (a non-GAAP measure defined as revenue including commodity derivative settlements and reconciled above) as compared to the prior year quarter.  Adjusted revenue for the quarter was $64.0 million, including the effect of commodity derivative settlement losses of $9.4 million.  Adjusted revenue for the comparable prior year period was $71.9 million, including the effect of commodity derivative settlement gains of $1.6 million.

During the first half 2018, Resolute realized a ten percent increase in revenue as compared to the first half of 2017 due principally to increased production and increased commodity pricing.  Revenue for the first half of 2018 was $148.1 million as compared to $134.9 million in the prior year period.  Resolute realized a four percent decrease in Adjusted revenue as compared to the prior year period.  Adjusted revenue for the first half of 2018 was $131.5 million, including the effect of commodity derivative settlement losses of $16.6 million.  Adjusted revenue for the comparable prior year period was $136.3 million, including the effect of commodity derivative settlement gains of $1.4 million.

Operating Expense:  For the second quarter 2018, LOE decreased by $4.5 million, or 23 percent, to $15.4 million, or $7.02 per Boe, as compared to second quarter 2017 LOE of $19.9 million, or $8.97 per Boe.  The 22 percent decrease in unit operating expense is primarily due to the Aneth Field Sale (Aneth Field had significantly higher operating costs as compared to our Delaware Basin properties) as well as the increase in Delaware Basin production.  The decrease was partially offset by a $1.5 million increase in workover expenses in the Delaware Basin during the 2018 period.  

Production taxes for the second quarter of 2018 remained relatively unchanged at $5.5 million (eight percent of revenue), or $2.52 per Boe from $5.6 million in 2017 (eight percent of revenue), or $2.51 per Boe.

For the first half of 2018, LOE decreased 29 percent to $27.0 million, or $6.28 per Boe, from 2017 LOE of $38.2 million, or $9.59 per Boe.  The decrease in unit operating expense is primarily due to the same reasons noted for the quarter over quarter decrease.  The decrease was partially offset by a $1.6 million increase in workover expenses in the Delaware Basin during the 2018 period.  

Production taxes for the first half of 2018 decreased to $11.1 million (eight percent of revenue) from $11.5 million in 2017 (nine percent of revenue).  On a Boe basis, production taxes decreased to $2.57 per Boe in 2018 from $2.89 per Boe in 2017.  The lower production and ad valorem taxes 2018 as compared to 2017 is primarily the result of the Aneth Field Sale.  All revenue in 2018 was recognized in the state of Texas, which has a lower tax rate than the Aneth Field properties in Utah, which were included in 2017 results. 

For the second quarter 2018, depletion, depreciation and amortization (“DD&A”) expense increased five percent to $23.5 million as compared to $22.3 million in 2017.  On a Boe basis, DD&A expense increased to $10.74 per Boe in 2018 from $10.08 per Boe in 2017 due primarily to capitalized costs increasing by a greater percentage than the associated proved reserve quantities period over period.

For the first half of 2018, DD&A expenses increased 23 percent to $47.0 million as compared to $38.4 million in 2017, partially as a result of the eight percent increase in production period over period. DD&A expenses increased on a Boe basis to $10.93 per Boe in 2018 from $9.62 per Boe in 2017 due to the same reason noted above.

General and Administrative Expense:  Resolute’s general and administrative expense increased 68 percent to $15.9 million during the second quarter 2018, as compared to $9.5 million during the same period in 2017.  The $6.4 million increase primarily resulted from approximately $3.1 million in stockholder activism costs and an increase of $1.6 million in non-cash share-based compensation expense during the 2018 quarter, as well as a decrease in certain overhead reimbursements, which reduce general and administrative expense, as a result of the Aneth Field Sale.  On a per-unit basis, general and administrative expense increased to $7.26 per Boe in 2018 from the $4.27 per Boe in 2017.  Cash-based general and administrative expense was $8.3 million, or $3.79 per Boe, in 2018 compared to $6.5 million, or $2.95 per Boe, in 2017.

For the first half of 2018, general and administrative expense increased 86 percent to $36.9 million during 2018, as compared to $19.9 million during the corresponding period of 2017.  The $17.0 million increase primarily resulted from two factors.  First, the Company incurred $6.4 million in stockholder activism costs in 2018. Second, an increase of $7.6 million of non-cash share-based compensation expense was reported during the six months ended June 30, 2018.  The Company incurred a one-time, non-cash increase of $6.0 million in stock-based compensation expense due to the modification and accelerated vesting of long-term incentive awards to employees terminated during the first half of 2018 as a result of the Aneth Field Sale.  The vesting terms of the outstanding long-term awards for affected employees was accelerated and recognized during the first quarter of 2018.  Additionally, certain overhead reimbursements, which reduce general and administrative expense, decreased period over period, also as a result of the Aneth Field Sale.  On a per-unit basis, general and administrative expenses increased to $8.59 per Boe in 2018 from the $4.98 per Boe in 2017.  Cash-based general and administrative expense was $17.2 million, or $4.00 per Boe, in 2018 compared to $14.1 million, or $3.54 per Boe, in 2017.

Cash-settled Incentive Awards:  Cash-settled incentive award expense increased by $1.3 million to a credit of less than $0.1 million during the second quarter 2018 as compared to a credit of $1.4 million in the second quarter of 2017.  This increase was the result of a change in the fair value related to the grant of cash-settled stock appreciation rights under the long-term incentive program.  These awards are marked to fair market value at each period end.  Actual cash payments during the 2018 period were $8.2 million, which includes the final payment of the Company’s performance-based restricted cash awards which were granted in 2015.

For the six months ended June 30, 2018, cash-settled incentive award expense increased to $11.3 million as compared to $4.0 million for the six months ended June 30, 2017.  The $7.3 million increase resulted from the modification in 2018 of certain long-term incentive awards as a result of the Aneth Field Sale.  The vesting of these awards was accelerated for affected employees and the expense was recognized during the first quarter of 2018.  Actual cash payments during the 2018 period were $14.4 million, which includes the final payment of the Company’s performance-based restricted cash awards as noted above.

Capital Expenditures:  During the quarter ended June 30, 2018, Resolute incurred oil and gas related capital expenditures of approximately $150.3 million.  Second quarter capital investment included $133.2 million of drilling, completion and well facility expenditures and $9.1 million spent on field facilities and infrastructure.  During the first six months of 2018, Resolute incurred oil and gas related capital expenditures of approximately $219.8 million.  Capital investment for 2018 included $192.3 million of drilling, completion and well facility expenditures and $12.1 million spent on field facilities and infrastructure.

Liquidity and Capital Resources:  Outstanding indebtedness of $673 million at June 30, 2018, consisted of $73 million in revolving credit facility debt and $600 million of senior notes, compared to total indebtedness of $555 million at December 31, 2017, an increase of $118 million.  In April 2018, the borrowing base under our revolving credit facility was reaffirmed at $210 million and the Company issued $75 million of additional senior notes.  

RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Operations (Unaudited)($ in thousands, except per share data)

	Three Months Ended June 30,								Six Months Ended June 30,
	2018				2017				2018				2017
Revenue:
Oil	$	58,395			$	60,703			$	118,046			$	118,362
Gas		5,670				6,468				12,030				10,819
Natural gas liquids		9,315				3,089				18,022				5,671
Total revenue		73,380				70,260				148,098				134,852
Operating expenses:
Lease operating		15,366				19,890				27,031				38,246
Production and ad valorem taxes		5,521				5,565				11,061				11,534
Depletion, depreciation and amortization		23,494				22,333				47,031				38,368
General and administrative		15,875				9,472				36,942				19,887
Cash-settled incentive awards		(47	)			(1,413	)			11,294				4,014
Total operating expenses		60,209				55,847				133,359				112,049
Income from operations		13,171				14,413				14,739				22,803
Other income (expense):
Interest expense, net		(8,515	)			(8,779	)			(16,083	)			(26,476	)
Commodity derivative instruments gain (loss)		(12,120	)			7,458				(21,522	)			18,298
Contingent payment derivative instrument gain		3,703				—				6,282				—
Other income (expense)		29				136				(5	)			76
Total other expense		(16,903	)			(1,185	)			(31,328	)			(8,102	)
Net income (loss)		(3,732	)			13,228				(16,589	)			14,701
Preferred stock dividends		(1,270	)			(2,538	)			(2,539	)			(3,935	)
Net income (loss) available to common stockholders	$	(5,002	)		$	10,690			$	(19,128	)		$	10,766
Net income (loss) per common share:
Basic	$	(0.22	)		$	0.49			$	(0.86	)		$	0.49
Diluted	$	(0.22	)		$	0.47			$	(0.86	)		$	0.47
Weighted average common shares outstanding:
Basic		22,306				21,917				22,194				21,828
Diluted		22,306				22,894				22,194				22,836

Reconciliation of Non-GAAP Measures

In this press release, the term “Adjusted net income (loss)” is used.  Adjusted net income (loss) is a non- GAAP financial measure and is equivalent to net income (loss) excluding non-cash items identified as affecting comparability of earnings between periods, which are non-cash mark-to-market (gains) losses on commodity and contingent payment derivative instruments, non-cash stock-based compensation expense related to the acceleration and vesting of long-term incentive awards to employees terminated as a result of the Aneth Field Sale and stockholder activism.  Resolute’s management uses Adjusted net income (loss) to evaluate the Company’s operating performance and believes that investors’ understanding of our performance is enhanced by disclosing this measure, which excludes certain items that management believes are not directly related to ongoing operations and are not indicative of future trends and operations.  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 net income (loss).

	Three Months Ended June 30,								Six Months Ended June 30,
	2018				2017				2018				2017
	($ in thousands)								($ in thousands)
Net income (loss)	$	(3,732	)		$	13,228			$	(16,589	)		$	14,701
Adjustments:
Mark-to-market (gain) loss		2,777				(5,802	)			4,902				(16,892	)
Contingent consideration gain		(3,703	)			—				(6,282	)			—
Stock-based Aneth transaction costs		—				—				6,014				—
Accrual of Aneth transaction cash-settled incentive awards		—				—				7,260				—
Stockholder activism		3,085				—				6,386				—
Adjusted net income (loss)	$	(1,573	)		$	7,426			$	1,691			$	(2,191	)
Adjusted net income (loss) per common share:
Basic	$	(0.07	)		$	0.34			$	0.08			$	(0.10	)
Diluted	$	(0.07	)			0.32			$	0.07			$	(0.10	)

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 June 30,								Six Months Ended June 30,
	2018				2017				2018				2017
	($ in thousands)								($ in thousands)
Net income (loss)	$	(3,732	)		$	13,228			$	(16,589	)		$	14,701
Adjustments:
Interest expense, net		8,515				8,779				16,083				26,476
Depletion, depreciation, and amortization		23,494				22,333				47,031				38,368
Stockholder activism		3,085				—				6,386				—
Stock-based compensation		4,497				2,978				13,709				5,951
Cash-settled incentive awards		(47	)			(1,413	)			11,294				4,014
Cash-settled incentive awards paid		(1,219	)			(1,384	)			(1,792	)			(1,384	)
Mark-to-market (gain) loss		2,777				(5,802	)			4,902				(16,892	)
Contingent consideration gain		(3,703	)			—				(6,282	)			—
Total adjustments		37,399				25,491				91,331				56,533
Adjusted EBITDA	$	33,667			$	38,719			$	74,742			$	71,234

In this press release, the term “cash-based general and administrative expense” is used.  We define cash-based general and administrative expense (a non-GAAP measure) as consolidated general and administrative expense adjusted to exclude non-cash stock-based compensation expense and one-time, non-recurring, transaction related expenses (transaction costs or fees).  An example of such fees and expenses are the fees and expenses that were incurred in conjunction with stockholder activism.  Resolute’s management believes cash-based general and administrative expense is an important metric that enables management to evaluate the Company’s activities and operations consistently between periods and through the normal course of our activities and operations.  This information differs from measures of our activities and operations determined in accordance with GAAP and should not be considered in isolation or as a substitute for measures of our activities and operations prepared in accordance with GAAP.  This measure may not be equivalent to similarly titled measures of other companies.  The table below reconciles Resolute’s general and administrative expense to cash-based general and administrative expense.

	Three Months Ended June 30,								Six Months Ended June 30,
	2018				2017				2018				2017
	($ in thousands)								($ in thousands)
General and administrative expense	$	15,875			$	9,472			$	36,942			$	19,887
Adjustments:
Non-cash stock-based compensation		4,489				2,934				13,339				5,753
Stockholder activism		3,085				—				6,386				—
Cash-based general and administrative expense	$	8,301			$	6,538			$	17,217			$	14,134

Earnings Call Information

Resolute will host an investor call on August 7, 2018, at 10:00 AM EDT. To participate in the call please dial (866) 548-4713 from the United States and Canada or (323) 794-2093 from outside the U.S. and Canada. Participants should dial in five to ten minutes before the scheduled time and must be on a touchtone telephone to ask questions. A replay of the call will be available through August 13, 2018, by dialing (844) 512-2921 from the U.S. and Canada, or (412) 317-6671 from outside the U.S. and Canada. The conference call replay number is 7777291.

Cautionary Statements

This press release includes “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as “expect,” “estimate,” “project,” “budget,” “forecast,” “anticipate,” “intend,” “plan,” “may,” “will,” “could,” “should,” “poised,” “believes,” “predicts,” “potential,” “continue,” and similar expressions are intended to identify such forward-looking statements; however the absence of these words does not mean the statements are not forward-looking. Such forward looking statements include statements regarding: future drilling plans and activity; future operating and production results; future liquidity and availability of capital; future infrastructure and other capital projects; our plans and expectations regarding our future development activities including drilling and completing wells; future adjustments to our completion designs; the number of such potential projects, locations and productive intervals, and years of additional drilling; anticipated 2018 and 2019 production and oil percentage; anticipated 2018 capital expenditures, LOE and G&A rates; expected third quarter Adjusted EBITDA; and funding of our 2018 capital program; and anticipated additional drilling inventory. Resolute will evaluate its capital expenditures in relation to its liquidity and cash flow and may adjust its activity and capital spending levels based on acquisitions, changes in commodity prices, the cost of goods and services, production results and other considerations. Forward-looking statements in this press release include matters that involve known and unknown risks, uncertainties and other factors that may cause actual results, levels of activity, performance or achievements to differ materially from results expressed or implied by this press release. Such risk factors include, among others: the Company’s ability to successfully implement its strategy to create long-term stockholder value; depressed commodity prices; the volatility of oil and gas prices and basis differentials, including the price realized by Resolute; inaccuracy in reserve estimates and expected production rates; disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, NGL and gas and other processing and transportation considerations; potential write downs of the carrying value and volumes of reserves as a result of low commodity prices; the discovery, estimation, development and replacement by Resolute of oil and gas reserves; our ability to find and develop our estimated proved undeveloped reserves and resources; changes in our production mix of oil and gas; the future cash flow, liquidity and financial position of Resolute; Resolute’s level of indebtedness and our ability to fulfill our obligations under the senior notes, our credit facility and any additional indebtedness that we may incur; potential borrowing base reductions under our revolving credit facility; constraints imposed on our business and operations by our revolving credit facility and senior notes which may limit our ability to execute our business strategy; the risk of a transaction that could trigger a change of control under our debt agreements; the success of the business and financial strategy, hedging strategies and development and production plans of Resolute; the amount, nature and timing of capital expenditures of Resolute, including future development costs; potential operational disruption caused by the actions of stockholder activists; the availability of additional capital and financing, including the capital needed to pursue our drilling and development plans for our properties, on terms acceptable to us or at all; uncertainty surrounding timing of identifying drilling locations and necessary capital to drill such locations; the potential for downspacing, infill or multi-lateral drilling in the Permian Basin or obstacles thereto; the timing of issuance of permits and rights of way; the timing and amount of future production of oil and gas; availability of drilling, completion and production personnel, supplies and equipment; the completion and success of exploratory drilling on our properties; potential delays in the completion, commissioning and optimization schedule of Resolute’s facilities construction projects or any potential breakdown of such facilities; operating costs and other expenses of Resolute; the success of prospect development and property acquisition of Resolute; risks associated with unanticipated liabilities assumed, or title, environmental or other problems resulting from, our acquisitions; the ability to sell or otherwise monetize assets at values and on terms that are advantageous to us; Resolute’s dependence on third parties for installation of gas gathering and processing infrastructure, oil gathering facilities and water disposal facilities and potential delays and breakdowns relating thereto; risks relating to our joint interest partners’ and other counterparties’ inability to fulfill their contractual commitments; the concentration of our credit risk as the result of depending on one primary oil purchaser and one primary gas purchaser in the Delaware Basin; the concentration of our producing properties in a single geographic area; loss of senior management or key technical personnel; the impact of long-term incentive programs, including performance-based awards and stock appreciation rights;  the success of Resolute in marketing oil and gas; competition in the oil and gas industry; the impact of weather and the occurrence of disasters, such as fires, floods and other events and natural disasters; environmental liabilities; potential power supply limitations or delays; operational problems or uninsured or underinsured losses affecting Resolute’s operations or financial results; adverse changes in government regulation and taxation of the oil and gas industry, including the potential for increased regulation of underground injection, fracing operations and venting/flaring; potential regulation of waste water injection intended to address seismic activity; potential climate related change regulations; risks and uncertainties associated with horizontal drilling and completion techniques; the availability of water and our ability to adequately treat and dispose of water during and after drilling and completing wells; our relationship with the local communities in which we operate; changes in derivatives regulation; risks associated with rising interest rates; the impact of any U.S. or global economic recession; losses possible from pending or future regulation; developments in oil-producing and gas-producing countries; risks of terrorist activities directed at oil and gas production; cyber security risks; and risks related to our common stock, potential declines in stock prices and potential future dilution to stockholders.  Actual results may differ materially from those contained in the forward-looking statements in this press release. Resolute undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after the date of this press release. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release. You are encouraged to review “Cautionary Note Regarding Forward Looking Statements” and “Item 1A - Risk Factors” and all other disclosures appearing in the Company’s Form 10-K and Form 10-K/A for the year ended December 31, 2017, subsequent quarterly reports on Form 10-Q and subsequent filings with the Securities and Exchange Commission (the “SEC”) for further information on risks and uncertainties that could affect the Company’s businesses, financial condition and results of operations. All forward-looking statements are qualified in their entirety by this cautionary statement. Production rates, including “early time” rates, 24-hour peak IP rates, 30, 60, 90, 120 and 150 day peak IP rates, and exit rates for both our wells and for those wells that are located near to our properties are limited data points in each well’s productive history and represent three stream gross production. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may change as additional data becomes available. Peak production and exit rates are not necessarily indicative or predictive of future production rates, EUR or economic rates of return from such wells and should not be relied upon for such purpose. Equally, the way we calculate and report peak IP rates and exit rates and the methodologies employed by others may not be consistent, and thus the values reported may not be directly and meaningfully comparable. Lateral lengths described are indicative only. Actual completed lateral lengths depend on various considerations such as leaseline offsets. Standard length laterals, sometimes referred to as 5,000 foot laterals, are laterals with completed length generally between 4,000 feet and 5,500 feet. Mid-length laterals, sometimes referred to as 7,500 foot laterals, are laterals with completed length generally between 6,000 feet and 8,000 feet. Long laterals, sometimes referred to as 10,000 foot laterals, are laterals with completed length generally longer than 8,000 feet. This press release may include certain non-GAAP financial measures. When applicable, a reconciliation of these measures to the most directly comparable GAAP measure is presented. 

About Resolute Energy Corporation

Resolute is an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin portion of the Permian Basin of west Texas. For more information, visit www.resoluteenergy.com. The Company routinely posts important information about the Company under the Investor Relations section of its website. The Company's common stock is traded on the NYSE under the ticker symbol "REN."

Contact:HB JuenglingVice President - Investor RelationsResolute Energy Corporation303-534-4600, extension 1555hbjuengling@resoluteenergy.com