Resolute Energy Corporation Announces Results for the Quarter Ended June 30, 2017

- Production of 24,355 Boe per day for the quarter, up 105% year over year -- Fourteen new wells on line since April 1 - - Initial production rates in Bronco in line with legacy wells - - Negotiating a definitive agreement to sell Aneth Field - 

Resolute Energy Corporation (“Resolute” or the “Company”) (NYSE:REN) today reported financial and operating results for the quarter and six months ended June 30, 2017.

Rick Betz, Resolute’s Chief Executive Officer, said: “Resolute has continued to ramp up production, driven by our successful drilling in the Delaware Basin.  Second quarter production averaged 24,355 barrels of oil equivalent (“Boe”) per day (63% oil and 78% liquids), an increase of 12,490 Boe per day, or 105 percent, from the prior year second quarter. On a sequential basis, second quarter production increased by 4,653 Boe per day, or 24 percent compared to first quarter volumes of 19,702 Boe per day.  Sequential production from our Permian Basin operations increased by 33 percent, from 13,798 Boe per day in the first quarter to 18,383 Boe per day in the second quarter and increased 227 percent from the prior year second quarter. These second quarter volumes include approximately 630 Boe per day from our newly acquired Bronco acreage. 

“Our production growth continued to accelerate through the end of the second quarter and into the third quarter, with estimated July production of approximately 29,500 Boe per day. Our Permian Basin production increased to 23,600 Boe per day during the month with the Bronco area contributing approximately 3,400 Boe per day. For the second quarter Aneth production was approximately 6,000 Boe per day, and once again essentially flat to the first quarter and the prior year despite continued restraint in capital spending.

“Net income for the second quarter was $13.2 million up from $1.5 million in the first quarter. Adjusted EBITDA (a non-GAAP measure) increased twelve percent to $32.4 million compared to $28.9 million in the first quarter. This increase in Adjusted EBITDA was achieved not just by increased production but also by continued improvement in lease operating expenses (“LOE”) more than offsetting weakness in commodity prices.  For the quarter, we saw LOE in our Delaware Basin operations decline to $4.87 per Boe produced from $5.42 per Boe in the first quarter. Cash general and administrative expenses (a non-GAAP measure) for the quarter also showed significant improvement, declining from $4.28 per Boe in the first quarter to $2.95 per Boe in the second quarter. 

“During the second quarter we spud seven wells and completed ten wells. We completed four mid-length laterals in Mustang with 24 hour peak IP rates averaging 2,584 Boe per day, two long laterals in Appaloosa with average initial 24 hour peak IP rates of 3,657 Boe per day and four drilled but uncompleted (“DUCs”) wells acquired in the Bronco transaction. At quarter-end we had four wells waiting on completion and three wells in various stages of drilling. Also during the quarter, we continued to de-risk our drilling inventory by completing two Wolfcamp B wells, one a mid-length lateral in central Mustang and one a mid-length lateral in Bronco.  We are continuing to study early-time production from these wells. As expected they look much stronger than earlier generation B wells.

“Year to date, we have reached total depth on sixteen wells. These include nine mid-length laterals and seven long laterals. We have completed and brought on line eighteen wells since January, including eleven mid-length laterals, four long laterals and three standard length laterals. Based on our current drilling schedule, we expect to spud the last well in our originally announced 22 well drilling plan early in the fourth quarter.  While we do not believe it would be prudent at this time to add a third rig to our program, our advanced drilling pace does give us the opportunity to expand the program with our existing rigs. Were we to keep both rigs running through year end it would result in up to five additional spuds in 2017. We will be evaluating this option over the coming months.

“Putting more focus on activities in Bronco, we closed the acquisition in May and immediately commenced completion operations on the six operated DUCs included in the transaction.  To date we have completed five of the wells including three Wolfcamp A wells and two Wolfcamp B wells. Two of the wells were mid-length laterals that were completed with 32 frac stages and had initial production in the first week of June.  The 24 hour peak IP rates on these two wells were 3,013 and 2,764 Boe per day, with currently calculated 30-day rates of 2,541 and 2,402 Boe per day, respectively.  These rates compare favorably with our Mustang and Appaloosa results.  The remaining four wells were standard length laterals.  Two of the wells were completed with 19 frac stages and came on line at the end of June.  We are encouraged by the 24 hour peak IP rates from these wells, averaging 2,300 Boe per day.  Of the last two wells, one well has been completed and is flowing back and the second well is waiting on completion.  We expect the seventh DUC acquired, an outside-operated well, to be completed in September.

“In addition to the drilling and completion activity, we made important progress on our field infrastructure.  In June we began shifting the gathering of our oil production from trucks into an oil pipeline constructed by our mid-stream partner.  By the end of July, substantially all Mustang and Appaloosa oil volumes were being gathered by pipeline.  This greatly simplifies the marketing of our production, it reduces our effective transportation costs, it entails less traffic impact on our in-field roads and other infrastructure, and it is expected to be more environmentally friendly than trucking the product to market. At this time, Bronco oil volumes continue to be gathered by truck, but we expect to move those volumes to pipe later this year.  Also in Bronco we completed the build out of production facilities which will support the long-term development of this asset. 

“During the second quarter we did experience a limited number of instances of well interference, primarily in Appaloosa, as we completed infill wells in close proximity to older producing wells in the same horizon.  We did not observe this same impact when drilling well pairs in Mustang. We estimate these events reduced company production for the quarter by approximately 1,000 to 1,200 Boe per day, or approximately four to five percent. These types of events are not atypical for development in the Permian Basin and have been reported by other operators as well.

“We have made operational adjustments based on our own observations and our review of recent industry best practices, which we believe will reduce these impacts in the future.  First, we anticipate that our future drilling will be done in groups of two to four wells followed by sequential frac operations on all of the wells in the group. We made this change starting with our two Ranger long laterals in Appaloosa in June.  These wells are currently waiting on completion.  That rig has moved and is currently drilling the first of two long lateral South Elephant wells which will be drilled together and then completed sequentially.  Importantly, the initial well on this pad is our first Wolfcamp C well. This well will help de-risk our Delaware Basin drilling inventory, satisfy depth clauses on certain leases and give us valuable data as we design future pad drilling operations. We expect these wells will be completed starting in October.  In Mustang we have one well to finish drilling before we shift to two well pads through the remainder of the year.  We believe this shift to pad drilling will result in savings of between $0.5 and $1.0 million dollars per pad.

“Second, we have moved to increase the density of perf clusters in our frac design.  We do not expect this to change our overall proppant loading or completion costs.  The goal of this revised design is to give us a more effective completion in the near wellbore environment while reducing the instances where individual fractures reach out long distances and negatively affect adjacent wells. 

“The shift to pad drilling is expected to modestly impact production growth in the second half of the year as a small number of completions are delayed.  Including our Bronco completion program, we remain comfortable with our previously announced guidance of 24,000 to 28,000 Boe per day, prior to any adjustment that may be required as a result of closing on the proposed Aneth divestiture. At the mid-point this would represent an increase of more than 83 percent over 2016 production levels. Additionally, we have experienced a modest shift in our oil percentage resulting from our mix of producing wells. Looking at our legacy assets we remain comfortable with our percentage oil guidance. However, as we bring additional Bronco wells on line we have observed gas to oil ratios consistent with Mustang, which has increased our blended gas to oil ratio marginally. Including anticipated production from Bronco, the Company’s percentage oil may decline by one to two percent.  From a capital expenditure standpoint, when we include approximately $37 million in net capital allocated to Bronco and approximately $15 million in increased capital associated with increased working interests in certain second quarter wells and unbudgeted outside-operated wells, we are increasing our capital guidance range to $270 million to $285 million. 

“As you know, we are actively pursuing the disposition of our Aneth Field assets.  We recently completed a thorough marketing process that resulted in multiple acceptable bids.  We are currently in negotiations on definitive documentation with our preferred counterparty.  We expect to announce a signing of such documents during the third quarter with the objective of closing the transaction in the fourth quarter. Upon a closing we anticipate reissuing production and cost guidance.  In the meantime, recall that we solidified our liquidity position with a $125 million add-on to our existing Senior Note due 2020, insuring that we were well positioned to close the Bronco acquisition as well as execute the drilling program.

“Finally, as we announced on August 2, Resolute’s Board of Directors has added two new members, Janet Pasque and Tod Benton.  Ms. Pasque and Mr. Benton bring a wealth of relevant experience to our board, an unwavering commitment to excellence and integrity, and a thoughtful approach to the industry and the Company.  As a result, the board now consists of nine members, six of whom are independent.  We welcome Janet and Tod, and are excited about their future contribution to the success of Resolute.” 

Operations Update

Following is an update of certain operating activities since April 1:

Drilling Activity:

Length

Spud to TD

Well Name

Area1

Zone2

(feet)

Status

TD date

(days)

Iron City State L05H

M

LWCA

7,717

Producing

4/25/2017

21

Steamworks 0304H

M

UWCA

7,489

Producing

5/21/2017

19

North Goat 2 Unit B101SL

A

WCB

10,218

Completing

5/26/2017

19

Breckenridge L06H

M

LWCA

7,825

Producing

6/13/2017

16

Ranger B106H

A

WCB

9,786

Completing

7/17/2017

23

Ranger L07H

A

LWCA

9,681

WOC

7/2/2017

19

Uinta L04HR

M

LWCA

7,620

Flowing back

7/11/2017

15

Ace L06H

M

LWCA

7,894

WOC

8/3/2017

15

South Elephant C207SL

A

WCC

9,465

Drilling

-

-

1. Area abbreviation legend: M – Mustang and A – Appaloosa and B – Bronco

2. Zone abbreviation legend: LWCA – Lower Wolfcamp A; UWCA – Upper Wolfcamp A; WCB –Wolfcamp B; WCC –Wolfcamp C

Completion Activity:

Length

First

Frac

Proppant per

Well Name

Area1

Zone2

(feet)

sales

stages

foot (lbs)

Pipeworks B05H

M

WCB

7,377

5/7/2017

29

1,818

Pipeworks L06H

M

LWCA

7,382

5/7/2017

29

1,797

South Goat 2 Unit U01H

A

UWCA

10,097

4/17/2017

37

1,772

North Elephant 2 Unit U06H

A

UWCA

9,571

5/27/2017

40

2,012

Iron City State L05H

M

LWCA

7,605

6/9/2017

33

2,008

Steamworks 0304H

M

UWCA

7,375

6/12/2017

32

2,065

Breckenridge L06H

M

LWCA

7,720

7/8/2017

29

1,803

Uinta L04HR

M

LWCA

7,510

Flowing back

27

1,796

Brigham Fuente 4402HL

B

LWCA

7,200

6/3/2017

32

2,013

Brigham Fuente 4401HU

B

WCB

7,025

6/3/2017

32

2,022

Durham Smith Fuente 207HL

B

WCB

4,541

WOC

-

-

Durham Smith Fuente 209HL

B

WCB

4,663

Flowing back

22

2,022

Durham Smith Fuente 212HU

B

UWCA

4,700

6/25/2017

19

1,992

Durham Smith Fuente 214HU

B

UWCA

4,616

6/25/2017

19

1,998

1. Area abbreviation legend: M – Mustang and A – Appaloosa and B – Bronco

2. Zone abbreviation legend: LWCA – Lower Wolfcamp A; UWCA – Upper Wolfcamp A; WCB –Wolfcamp B

Production Activity:

										Peak rate				Peak rate				Peak rate
						Length				24 hour				30 day				60 day
Well Name		Area1		Zone2		(feet)				Boe per day				Boe per day				Boe per day
South Elephant U04H		A		UWCA			8,902				2,716				2,351				2,198
Pipeworks B05H		M		WCB			7,377				2,727				2,393				2,112
Pipeworks L06H		M		LWCA			7,382				2,653				2,294				2,024
South Goat 2 Unit U01H		A		UWCA			10,097				3,766				3,517				3,180
North Elephant 2 Unit U06H		A		UWCA			9,571				3,549				3,129				2,534
Iron City State L05H		M		LWCA			7,605				2,827				2,563			-
Steamworks 0304H		M		UWCA			7,375				2,129				1,954			-
Breckenridge L06H		M		LWCA			7,720				2,728			-				-
Uinta L04HR		M		LWCA			7,510			-				-				-
Durham Smith Fuente 201HL3		B		WCB			4,507				1,642				1,543				1,413
Durham Smith Fuente 204HU3		B		UWCA			4,506				1,788				1,584				1,512
Brigham Fuente 4402HL		B		LWCA			7,200				3,013				2,541			-
Brigham Fuente 4401HU		B		WCB			7,025				2,764				2,402			-
Durham Smith Fuente 209HL		B		WCB			4,663			-				-				-
Durham Smith Fuente 212HU		B		UWCA			4,700				2,029				1,343			-
Durham Smith Fuente 214HU		B		UWCA			4,616				2,551				1,866			-
1. Area abbreviation legend: M – Mustang and A – Appaloosa and B – Bronco
2. Zone abbreviation legend: LWCA – Lower Wolfcamp A; UWCA – Upper Wolfcamp A; WCB –Wolfcamp B
3. The Durham Smith Fuente 201HL and 204HU were acquired as producing wells

See “Cautionary Statements” below for a discussion of the nature of these production metrics.

Second Quarter Comparative Results

Resolute recorded net income available to common shareholders of $10.7 million, or $0.47 per diluted share, on revenue of $71.0 million during the three months ended June 30, 2017.  Included in net income was $7.5 million of commodity derivative gains.  This compares to a net loss of $36.9 million, or $2.44 per share, on revenue of $35.4 million during the three months ended June 30, 2016.  The 2016 loss included commodity derivative losses of $19.6 million.

For the six months ended June 30, 2017, Resolute recorded net income available to common shareholders of $10.8 million, or $0.47 per diluted share, on revenue of $136.3 million.  Included in net income was $18.3 million of commodity derivative gains.  This compares to a net loss of $122.2 million or $8.10 per share, on revenue of $54.4 million.  The 2016 loss included commodity derivative losses of $15.7 million and a non-cash impairment charge of $58 million.

Second Quarter and Six Months 2017 Results Compared to Second Quarter and Six Months 2016 Results
		Three Months Ended June 30,								Six Months Ended June 30,
		2017				2016				2017				2016
		($ thousands, except per-Boe amounts)
Production (MBoe):
Permian			1,673				511				2,915				780
Aneth			543				569				1,074				1,120
Total production			2,216				1,080				3,989				1,900
Daily rate (Boe)			24,355				11,865				22,041				10,441
Revenue per Boe (excluding commodity derivative settlements)		$	32.05			$	32.78			$	34.15			$	28.62
Revenue per Boe (including commodity derivative settlements)		$	32.79			$	51.81			$	34.51			$	54.04
Revenue		$	71,026			$	35,390			$	136,252			$	54,392
Commodity derivative settlements			1,656				20,544				1,406				48,292
Revenue, including derivative settlements			72,682				55,934				137,658				102,684
Operating expenses:
Lease operating expense		$	19,890			$	15,689			$	38,246			$	29,506
Production and ad valorem taxes			6,331				4,248				12,934				7,390
Depletion, depreciation, amortization and  asset retirement obligation accretion			22,333				10,865				38,368				21,226
Impairment of proved oil and gas properties			—				—				—				58,000
General and administrative expense			9,472				7,530				19,887				16,498
Cash-settled incentive awards			(1,413	)			1,435				4,014				2,233
Net income (loss)		$	13,228			$	(36,906	)		$	14,701			$	(122,218	)
Adjusted EBITDA		$	32,442			$	28,362			$	61,360			$	51,515

Adjusted EBITDA (a non-GAAP measure):  During the second quarter of 2017, Resolute generated $32.4 million of Adjusted EBITDA, or $14.64 per Boe, a fourteen percent increase from the prior year period, during which Resolute generated $28.4 million of Adjusted EBITDA, or $26.27 per Boe.  The increase in Adjusted EBITDA was the result of increased revenue due to increased production, partially offset by decreased commodity derivative settlements and an increase in cash-settled incentive awards paid as compared to the prior period.

During the first six months of 2017, Resolute generated $61.4 million of Adjusted EBITDA, or $15.38 per Boe, a nineteen percent increase from the prior period, during which Resolute generated $51.5 million of Adjusted EBITDA, or $27.11 per Boe.  The increase in Adjusted EBITDA resulted primarily from the reasons noted above as well as increased revenue from increased commodity pricing as compared to the 2016 period.

Production:  Production for the quarter ended June 30, 2017, increased 105 percent to 2,216 MBoe, or 24,355 Boe per day, as compared to 1,080 MBoe, or 11,865 Boe per day, during the second quarter of 2016.  During the first half of 2017, production increased 110 percent to 3,989 MBoe, or 22,041 Boe per day, from 1,900 MBoe, or 10,441 Boe per day, during the first half of 2016.  The increases from the comparable prior year periods were attributable to positive results from the 2017 drilling and completion program in the Permian Basin.   

Production from the Company’s Permian Basin properties increased more than 200 percent to 18,383 Boe per day, as compared to the 5,614 Boe per day produced in the second quarter of 2016, and increased 33 percent from the 13,798 Boe per day produced during the first quarter of 2017.  During the first half of 2017, production increased more than 250 percent to 16,103 Boe per day from the 4,287 Boe per day produced during the first half of 2016. 

Second quarter 2017 production from the Company’s Aneth Field properties decreased four percent to 5,972 Boe per day as compared to the 6,251 Boe per day produced in the second quarter of 2016, and remained relatively unchanged from the 5,904 Boe per day produced during the first quarter of 2017.  During the first half of 2017, production decreased four percent to 5,938 Boe per day from the 6,154 per day produced during the first half of 2016.

Revenue:  During the second quarter of 2017, Resolute realized a 30 percent increase in adjusted revenue (revenue including commodity derivative settlements), a non-GAAP measure, as compared to the prior year quarter due to increased production attributable to positive results from the drilling and completion program in the Delaware Basin partially offset by decreased derivative settlement gains as compared to the prior year period.  Adjusted revenue for the quarter was $72.7 million, including the effect of commodity derivative settlement gains of $1.7 million.  During the second quarter of 2016, Resolute had adjusted revenue of $55.9 million, including the effect of commodity derivative settlement gains of $20.5 million.

During the first half of 2017, Resolute realized a 34 percent increase in adjusted revenue as compared to the first half of 2016, due to the reasons noted above.  Adjusted revenue for the six months ended June 30, 2017 was $137.7 million, including the effect of commodity derivative settlement gains of $1.4 million.  For the six months ended June 30, 2016, Resolute had adjusted revenue of $102.7 million, including the effect of commodity derivative settlement gains of $48.3 million.

Operating Expenses:  For the second quarter of 2017, LOE increased $4.2 million, or 27 percent, to $19.9 million, or $8.97 per Boe, as compared to second quarter 2016 LOE of $15.7 million, or $14.53 per Boe.  The decrease in unit operating expense is due to the significant increase in production from mid-length and long lateral horizontal wells in the Delaware Basin, which increased by a greater percentage than the associated LOE.  Production taxes increased by $2.1 million, or 49 percent, to $6.3 million (nine percent of revenue) from $4.2 million (twelve percent of revenue) in 2016.  Conversely, production taxes decreased on a Boe basis to $2.86 per Boe in 2017 from $3.93 per Boe in 2016.  The lower production and ad valorem taxes as a percentage of revenue in 2017 as compared to 2016 is attributable to the increase in the percentage of revenue realized in the state of Texas, which has a lower tax rate than the Aneth Field properties in Utah.  This decrease is also the result of the timing of the assessment of ad valorem taxes, as they are assessed on January 1st of each year, based on the producing wells at that point in time and are not updated for wells that come online throughout the year.

For the first six months of 2017, LOE increased 30 percent to $38.2 million, or $9.59 per Boe, from 2016 LOE of $29.5 million, or $15.53 per Boe.  The decrease in unit operating expense is due to the reasons noted above.  Production taxes increased by $5.5 million, or 75 percent, to $12.9 million (ten percent of revenue) as compared to $7.4 million (fourteen percent of revenue) in 2016, and decreased on a Boe basis to $3.24 per Boe in 2017 from $3.89 per Boe in 2016 due to the reasons noted above.

For the second quarter of 2017, depletion, depreciation, amortization and accretion (“DD&A”) expenses increased 106 percent to $22.3 million as compared to the second quarter of 2016 DD&A expenses of $10.9 million as a result of the 105 percent increase in production period over period.  On a Boe basis, DD&A expenses remained relatively unchanged at $10.08 per Boe in 2017 compared to $10.06 per Boe in 2016.

For the first six months of 2017, DD&A expenses increased 81 percent to $38.4 million as compared to the first six months of 2016 expenses of $21.2 million principally as a result of the 110 percent increase in production period over period.  Conversely, DD&A expenses decreased on a Boe basis to $9.62 per Boe in 2017 from $11.17 per Boe in 2016, which is attributable to proved reserve quantities increasing by a greater percentage than the associated capitalized costs period over period.

Pursuant to full cost accounting rules, we perform a ceiling test each quarter on our proved oil and gas assets.  No impairment was recorded during the three or six months ended June 30, 2017.  However, we recorded a $58 million non-cash impairment of the carrying value of our proved oil and gas properties during the six months ended June 30, 2016 as a result of the ceiling test limitation. 

General and Administrative Expense:  Resolute’s general and administrative expenses increased 26 percent to $9.5 million during the second quarter of 2017, as compared to $7.5 million during the same period in 2016.  The $2.0 million increase primarily resulted from increases in share based compensation due to a shift from granting principally cash-based incentive awards in 2016 and 2015 to equity-based long-term incentive awards in 2017.  On a unit-of-production basis, general and administrative expenses decreased 39 percent.  Cash-based general and administrative expense for the second quarter of 2017 was $6.5 million, or $2.95 per Boe, compared to $6.2 million, or $5.74 per Boe, in the comparable 2016 period.  Share-based compensation expense, a non-cash item, represented $3.0 million for the second quarter of 2017 and $1.3 million for the second quarter of 2016. 

For the first six months of 2017, general and administrative expenses increased to $19.9 million, as compared to $16.5 million during 2016.  The $3.4 million, or 21 percent, increase primarily resulted from the reason noted above as well as a restoration of short-term incentive compensation awards, which had been reduced during 2016 in response to lower commodity prices, offset by an increase in the portion of general and administrative expenses capitalized.  Cash-based general and administrative expense for the first half of 2017 was $14.1 million, or $3.54 per Boe, compared to $13.0 million, or $6.82 per Boe in the comparable 2016 period.  Share-based compensation expense represented $5.8 million for the first six months of 2017 and $3.5 million for the first six months of 2016.

Cash-settled Incentive Awards:  We recorded a credit of $1.4 million during the second quarter of 2017 for cash-settled incentive award expenses as compared to expense of $1.4 million in the second quarter of 2016.  The decrease is attributable to a decrease in the fair value of cash-settled stock appreciation rights under the long-term incentive program, which are required to be remeasured at each period end.  Due to a decrease in the price of Resolute common stock during the second quarter of 2017, the remeasurement of the fair value of the awards yielded a lower fair value than at March 31, 2017. As a result, a credit was recorded during the second quarter of 2017.  Actual cash payments for the current quarter were $7.7 million. 

For the six months ended June 30, 2017, cash-settled incentive award expenses increased to $4.0 million as compared to $2.2 million for the six months ended June 30, 2016.  The 2017 increase in expense is a result of the grant of time- and performance-based restricted stock awards, the achievement of multiple performance targets under the performance-based restricted cash awards as well as cash-settled stock appreciation rights under the long-term incentive program that are based on the Company’s common stock price.  Actual cash payments during the 2017 period were $11.3 million.

Capital Expenditures:  During the quarter ended June 30, 2017, Resolute incurred oil and gas related capital expenditures of approximately $93.7 million, excluding the Delaware Basin Bronco Acquisition of $161.3 million and capitalized interest of $3.7 million.  During the first six months of 2017, Resolute incurred oil and gas related capital expenditures of approximately $147.1 million, excluding the Delaware Basin Bronco Acquisition of $161.3 million and capitalized interest of $6.2 million.  These capital investments were primarily for drilling and completion, and facility and infrastructure projects in the Delaware Basin.

Liquidity and Capital Resources:  Outstanding indebtedness of $625 million at June 30, 2017, consisted of $100 million in revolving credit facility debt and $525 million of senior notes, compared to total indebtedness of $538.3 million at December 31, 2016, an increase of $86.7 million.  During the first half of 2017, we repaid all amounts outstanding on the Secured Term Loan Facility and entered into the Third Amended and Restated Credit Agreement with an initial borrowing base of $150 million.  Pursuant to the spring borrowing base redetermination, our borrowing base was increased to $225 million, effective April 17, 2017.  Additionally, in May 2017, Resolute issued an additional $125 million aggregate principal amount of the Company’s 8.50% senior notes due 2020, under the same indenture as the $400 million senior notes that were previously issued.  As a result of the issuance of the additional senior notes, the borrowing base was reduced to $218.8 million.

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,
		2017				2016				2017				2016
Revenue:
Oil		$	60,703			$	33,483			$	118,362			$	51,278
Gas			7,216				1,210				12,173				2,188
Natural gas liquids			3,107				697				5,717				926
Total revenue			71,026				35,390				136,252				54,392
Operating expenses:
Lease operating			19,890				15,689				38,246				29,506
Production and ad valorem taxes			6,331				4,248				12,934				7,390
Depletion, depreciation, amortization, and asset retirement  obligation accretion			22,333				10,865				38,368				21,226
Impairment of proved oil and gas properties			—				—				—				58,000
General and administrative			9,472				7,530				19,887				16,498
Cash-settled incentive awards			(1,413	)			1,435				4,014				2,233
Total operating expenses			56,613				39,767				113,449				134,853
Income (loss) from operations			14,413				(4,377	)			22,803				(80,461	)
Other income (expense):
Interest expense, net			(8,779	)			(12,983	)			(26,476	)			(26,058	)
Commodity derivative instruments gain (loss)			7,458				(19,552	)			18,298				(15,711	)
Other income			136				6				76				12
Total other expense			(1,185	)			(32,529	)			(8,102	)			(41,757	)
Net income (loss)			13,228				(36,906	)			14,701				(122,218	)
Preferred stock dividends			(2,538	)			—				(3,935	)			—
Net income (loss) available to common shareholders		$	10,690			$	(36,906	)		$	10,766			$	(122,218	)
Net income (loss) per common share:
Basic		$	0.49			$	(2.44	)		$	0.49			$	(8.10	)
Diluted			0.47				(2.44	)		$	0.47			$	(8.10	)
Weighted average common shares outstanding:
Basic			21,917				15,155				21,828				15,096
Diluted			22,894				15,155				22,836				15,096

Reconciliation of Net Income (Loss) to Adjusted EBITDA

In this press release, the term “Adjusted EBITDA” is used.  Adjusted EBITDA is a non-GAAP financial measure and is equivalent to earnings before interest, income taxes, depreciation, depletion, amortization and accretion expenses, stock-based compensation, cash-settled incentive awards, mark-to-market commodity derivative gain (loss), 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,
		2017				2016				2017				2016
		($ in thousands)								($ in thousands)
Net income (loss)		$	13,228			$	(36,906	)		$	14,701			$	(122,218	)
Adjustments:
Interest expense, net			8,779				12,983				26,476				26,058
Income tax (benefit) loss			—				—				—				—
Depletion, depreciation, amortization and  asset retirement obligation accretion			22,333				10,865				38,368				21,226
Impairment of proved oil and gas properties			—				—				—				58,000
Stock-based compensation			2,979				1,409				5,952				3,733
Cash-settled incentive awards accrued			(1,413	)			1,435				4,014				2,233
Cash-settled incentive awards paid			(7,662	)			(1,520	)			(11,259	)			(1,520	)
Mark-to-market (gain) loss			(5,802	)			40,096				(16,892	)			64,003
Total adjustments			19,214				65,268				46,659				173,733
Adjusted EBITDA		$	32,442			$	28,362			$	61,360			$	51,515

Earnings Call Information

Resolute will host an investor call on August 8, 2017, at 7:30 AM EDT. To participate in the call please dial (800) 474 - 8920 from the United States or Canada or (719) 457- 2605 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 15, 2017, by dialing [phone] from the U.S. or Canada, or (412) 317- 6671 from outside the U.S. The conference call replay number is 5047730.

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. Such forward looking statements include statements regarding 2017 production guidance; 2017 oil percentage guidance; anticipated capital expenditures and activity in 2017; future financial and operating results; liquidity and availability of capital; the anticipated execution of definitive documentation relating to the disposition of Aneth Field and the anticipated closing thereof; future infrastructure and other capital projects; future production, reserve growth and decline rates; the impact of well interference and the effectiveness of operational adjustments with respect thereto; expected timing of drilling and completion of pad wells and the timing of the production contribution thereof; our plans and expectations regarding our future development activities including drilling, deepening, recompleting, fracing and refracing wells, the number of such potential projects, locations and productive intervals, and the prospectivity of our properties and acreage. 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: commodity prices; the volatility of oil and gas prices including the price realized by Resolute for the oil and gas it sells; inaccuracy in reserve estimates and expected production rates; the discovery, estimation, development and replacement by Resolute of oil and gas reserves and the risks associated with the potential writedown of reserves; 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; the success of the business and financial strategy, hedging strategies and plans of Resolute; the amount, nature and timing of capital expenditures of Resolute, including future development costs; the availability of additional capital and financing, including the capital needed to pursue our acquisition strategy and our drilling and development plans for our properties, on terms acceptable to us or at all; the effectiveness of Resolute’s CO2 flood program; uncertainty surrounding timing of identifying drilling locations and necessary capital to drill such locations; the potential for down-spacing, 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; timing of installation of gathering and processing infrastructure in new areas of development, including Resolute’s dependence on third parties for such items; 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; anticipated supply of CO2, which is currently sourced exclusively under a contract with Kinder Morgan CO2 Company, L.P.; potential power supply interruptions, 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 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; changes in derivatives regulation; developments in oil-producing and gas- producing countries; Resolute’s relationship with the Navajo Nation and the local communities in the areas in which Resolute operates; and cyber security risks. 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 for the year ended December 31, 2016, and subsequent filings with the Securities and Exchange Commission 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.

Lateral lengths of wells described in this release 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 6,500 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.

Finally, production rates, including 24 hour, 30 day and 60 day peak IP rates, for both our wells and for wells that are operated by others are limited data points in each well’s productive history. Also, different operators have different operating philosophies, particularly early in the life of a well. Finally, the way we calculate and report 24 hour, 30 day and 60 day peak IP rates and the methodologies used by others may not be consistent, thus the values reported may not be directly and meaningfully comparable. As a result, these metrics may not be 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. You are urged to consider closely the disclosure in Resolute’s Annual Report on Form 10- K filed on March 13, 2017, in particular the factors described under “Risk Factors.”

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. Resolute also operates Aneth Field, located in the Paradox Basin in Utah. 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 Juengling
Vice President - Investor Relations
Resolute Energy Corporation
303-534-4600, extension 1555
[e-mail]