Exhibit 99.1

RESOLUTE ENERGY CORPORATION ANNOUNCES RESULTS

FOR THE THIRD QUARTER ENDED SEPTEMBER 30, 2012

- Production increased 18 percent quarter-over-quarter to 9,365 Boe per day -

- Nine month production up 360% in North Dakota and 374% in Texas -

- Aneth Unit production up 22% during the first nine months of 2012 -

- Recompleted three wells in the McElmo Creek Unit DC IIC formation -

Denver, Colorado – November 5, 2012 – Resolute Energy Corporation (“Resolute” or the “Company”) (NYSE: REN) today reported financial and operational results for the three and nine month periods ended September 30, 2012.

Highlights for the quarter ended September 30, 2012, include the following:

Nicholas J. Sutton, Resolute’s Chairman and Chief Executive Officer said: “I am pleased to be able to confirm that our production growth remains on target, and we are confident that we will exit the year meeting our production goals that we shared with you previously. That incremental production is coming from our core areas, including Aneth Field, the Bakken trend and the Permian Basin.

“During the quarter, Aneth Field continued to show positive results associated with our ongoing CO₂ flood program. To date that activity has been focused on the Aneth Unit, and we are pleased that we continue to see production growth from Phases 1, 2 and 3. In addition we have seen early production response from Phase 4, where we only recently started to inject CO₂. Aneth Field also benefited from the results of certain operational activities, such as sidetracking several production and injection wells, and achieving increasingly better run times at the Aneth Unit central compression facility. Also, in the McElmo Creek Unit of Aneth Field, our work in the DC IIC formation continued, with activity on three producers and one injector during the quarter.

“In North Dakota we increased oil production almost five-fold from the prior year, and the commissioning of a new walking rig has provided an excellent opportunity for the operator to increase operational efficiencies, improve returns and support an accelerated pace of drilling activity.

“In addition to our drilling in the Permian Basin, where we placed 6 gross (4.0 net) wells on production, we focused on operational improvements that included installing cost-saving electrical infrastructure, drilling and completing a salt water disposal well and testing alternative production methods such as electrical submersible pumps and gas lift systems, all aimed at decreasing costs, enhancing productivity and improving profitability. We also have been able to improve drilling performance in both the Delaware and Midland basins.

“In Hilight Field, we have resumed our Muddy refrac program and we anticipate undertaking another four Muddy refracs during the fourth quarter.

“With our increased operational activity came an increase in lease operating expenses. Third quarter lease operating expense increased approximately nine percent from the second quarter as a result of expanded operations in Texas and North Dakota, and an aggressive increase in activity to reduce well downtime and improve production in Aneth Field. Particularly in Aneth Field, these costs were reflected in our operating income in a single quarter, while the production benefits are realized over upcoming quarters and years. We also saw generally higher supply costs across all areas.

“Our management team has done an excellent job of diversifying the Company's asset portfolio into some of the nation's most compelling oil plays, and ramping-up drilling activity to increase production. Our assets in the Permian Basin and in the Bakken oil shale trend of North Dakota provide us with attractive projects for reinvesting the substantial free cash flow generated by our foundation Aneth Field. We have the financial resources to continue our enhancement and development operations in Aneth Field and run continuous drilling programs in the Permian Basin and the Bakken trend, providing the basis for driving further oil production increases.”

Operations Update

Greater Aneth Field – Paradox Basin

Our Aneth Field properties had production for the quarter of 6,399 Boe per day compared to 5,923 Boe per day a year ago and 6,648 Boe per day in the second quarter. The quarterly sequential production decrease was due primarily to the sale of working interests to Navajo Nation Oil and Gas Company (“NNOGC”) that occurred on July 2, 2012. Without the disposition, third quarter production would have been flat compared to the prior quarter. In the Aneth Unit, five more wells were sidetracked and completed during the third quarter, contributing to an initial production increase of approximately 130 gross Boe per day. We plan to sidetrack three more wells in the fourth quarter. In Phase 4 of our expansion of the Aneth Unit CO₂ flood, activity focused on facility upgrades at the main battery and production header to handle increased oil, gas and water volumes. We have seen production response in several Phase 4 producing wells as a result of CO₂ injected in the adjacent Phase 3 area as well as early injections within the Phase 4 area itself. As a result of activities across the Aneth Unit, September daily production was an impressive 22 percent increase over January, 2012, production.

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In the adjacent McElmo Creek Unit, two additional producers were completed in the Desert Creek IIC zone, with incremental production of almost 200 gross Boe per day. One more producer and four injectors are expected to be completed by year-end 2012. By year-end we expect to have 21 producers and 26 injectors online in this project.

During the third quarter, runtime at the Aneth Unit compression facility reached 95 percent, an improvement over the 90 percent run time experienced in the second quarter. Improved runtime increases condensate production and CO₂ reinjection capacity, and decreases flaring and backpressure on the producing wells. Current reinjection capacity is 45 million cubic feet per day ("MMcfd") and we plan to increase capacity to 60 MMcfd by year-end through the installation of additional compression.

In the first half of 2012, we temporarily increased the number of workover rigs operating in the field to a peak of eleven rigs in order to accelerate activities devoted to repairing down wells, and deepening and sidetracking wells. This increased level of workover activity continued somewhat into the third quarter. Looking forward, we expect six rigs will be required for steady-state operations. We also expect that rig activity will slow incrementally in the winter months, when weather-related constraints make operating conditions more difficult and less efficient.

North Dakota Bakken Trend—Williston Basin

During the third quarter of 2012 we produced 919 Boe per day net to Resolute, up 362 percent from 199 Boe per day produced in the same quarter last year, and up twenty percent from the 765 Boe per day produced in the second quarter of 2012. We placed 10 gross (2.2 net) wells on production during the third quarter, bringing our total producing well count to 49 gross (11.9 net). Additionally, at the end of the third quarter we had 5 gross (0.8 net) wells drilled and waiting on completion. We expect those wells will begin producing during the fourth quarter. At quarter-end we were participating in drilling 5 gross (1.2 net) wells.

In the New Home project we own leasehold interests in approximately 23,500 net acres with plans to continue a two-rig drilling program for the rest of 2012. Since the operator replaced one of the conventional rigs with a new walking rig, drilling and completion costs declined, and in the third quarter per well AFE costs were approximately $7.7 million, down from $8.0 million in the second quarter of this year and substantially below costs experienced in 2011. We hope to see further cost reductions as the operator refines processes and increases cost efficiencies.

In January of this year we assumed operatorship of our 19,000 gross (8,500 net) acre Paris project area. The second well drilled in the Paris project was the Forest USA 14-2H. This well had mechanical issues during the initial stimulation treatment that resulted in only six stages being completed. We fraced the remaining eighteen stages in July, and it flowed back at a 30-day average production rate of more than 560 gross Boe per day. These results are consistent with those from offsetting wells, and we plan to drill more wells in the Paris project during 2013.

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Permian Basin – Texas

We operate in the Delaware and Midland basins of the Permian Basin of Texas, where we produced 600 Boe per day net to Resolute during the third quarter of 2012, up 111 percent from the 284 Boe per day produced in the prior year quarter, and up 41 percent from the 427 Boe per day produced in the second quarter of 2012. We placed 6 gross (4.0 net) wells on production during the third quarter, bringing our total producing well count to 25 gross (18.1 net). Additionally, at the end of the third quarter we had 2 gross (1.5 net) wells drilled and waiting on completion and hookup. We expect those wells to be on production during the fourth quarter. We maintain a continuous drilling program in the basin, and at the end of the quarter we were drilling 3 gross (2.0 net) wells.

In Reeves County in the Delaware Basin, we control approximately 22,500 gross (8,100 net) acres, prospective primarily for Wolfbone production. In the Midland Basin, we own leasehold covering approximately 750 net and gross acres with infill drilling and uphole recompletion potential. We continue to look for opportunities to increase our land position in both basins to complement our existing positions.

In the Wolfbone play in Reeves County, we continue to focus on drilling vertical wells targeting the Wolfcamp and Bone Spring formations. During most of the third quarter, we maintained a two-rig drilling program, and at the end of the quarter we released one rig. We expect to operate one rig in this area through the remainder of 2012.

We continue to make improvements to our operating efficiencies and productivity in the Delaware Basin. In the third quarter, we reduced total drilling days (spud to total depth) to 20 to 25 days, down from 30 to 35 days. Improved drilling performance and modifications to the completion design have reduced our total drilling and completion costs to approximately $3.5 million per well from $4.1 million. To improve operational efficiencies, we completed the majority of the electrical infrastructure and started the process of energizing the system in October. This power infrastructure will bring electricity to our pumping and compression units in the area, allowing us to replace stand-alone generators at each wellsite. Continued improvements to our water disposal facilities, including placing into service our salt water disposal well and installing water gathering lines from the field, will eliminate expensive trucking costs for water hauling and reduce water disposal costs. After bringing the water disposal facilities online in the third quarter, we experienced a reduction in disposal costs.

We are also testing the potential for improving efficiencies through installation of electrical submersible pumps and gas lift systems. These activities required us to operate as many as three workover rigs during the third quarter, which increased lease operating expenses. We anticipate operating one workover rig in the Permian Basin during the fourth quarter.

In the Midland Basin our drilling performance improved in the third quarter, as we reduced total drilling days by approximately five days, which decreased drilling and completion costs to $2.8 million, a reduction of ten percent from $3.1 million in the prior quarter. Combined, improved productivity and cost-saving operational improvements enhance returns and cash flow.

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Hilight Field—Powder River Basin

In Hilight Field we produced 1,441 Boe per day net to Resolute during the third quarter, down five percent from 1,511 Boe per day produced during the same quarter last year and down eight percent from the 1,566 Boe per day produced during the second quarter of this year. The lower production level is a result of normal production declines and a temporary maintenance outage at the Anadarko Hilight Gas Plant.

We resumed our refrac program targeting the Muddy formation during the third quarter and expect to continue the initiative in 2013. The program was resumed after giving our engineering team time to analyze the results to date of our three year refrac program, from which they developed model criteria for selected refrac candidates.

In addition, we are continuing to process and interpret data from the 3-D seismic survey we finished earlier in the year, covering 90 square miles over and adjacent to our Hilight Field. All of our 45,000 net acre position in the multi-pay, multi-play Hilight Field is held by production, and we anticipate the 3-D seismic will help us identify and high-grade the most compelling oil plays in the project area.

Third Quarter and Nine Month Comparative Results

Resolute recorded a net loss of $2.5 million, or $(0.04) per diluted share, on revenue of $63.4 million during the three months ended September 30, 2012, which included unrealized losses on derivative instruments of $3.5 million. This compares to net income of $37.6 million, or $0.59 per diluted share in the third quarter of 2011, which included unrealized gains on derivative instruments of $56.4 million.

For the nine months ended September 30, 2012, Resolute achieved net income of $19.6 million or $0.32 per diluted share, on revenue of $191.4 million, which included unrealized gains on derivative instruments of $30.0 million. This compares to net income of $46.5 million, or $0.70 per diluted share in the 2011 period, which included unrealized gains on derivative instruments of $48.8 million.

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Third Quarter and Nine Months 2012 Results Compared to Third Quarter and Nine Months 2011 Results

Adjusted EBITDA (a non-GAAP measure): During the third quarter of 2012, Resolute generated $26.4 million of Adjusted EBITDA, or $30.66 per Boe, a one percent increase from the prior year period during which Resolute generated $26.1 million of Adjusted EBITDA, or $35.79 per Boe. Although production increased materially, increased operating costs, production taxes and general and administrative expenses resulted in a decrease in Adjusted EBITDA per Boe.

During the nine months of 2012, Resolute generated $76.8 million of Adjusted EBITDA, or $30.93 per Boe, a four percent decrease from the prior year period. During the comparable prior year period, Resolute generated $79.9 million of Adjusted EBITDA, or $36.89 per Boe. The reasons for the nine month decrease were substantially the same as those discussed for the quarterly decrease.

Production: Company-wide production for the quarter ended September 30, 2012, increased eighteen percent to 862 MBoe as compared to 729 MBoe for the third quarter of 2011, and is consistent with the second quarter of 2012. Production for the nine months ended September 30, 2012, was 2,482 MBoe as compared to 2,165 MBoe for the nine month period in 2011, an increase of fifteen percent or 317 MBoe.

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Third quarter production from the Company’s Aneth Field properties increased eight percent to 589 MBoe from 545 MBoe during the comparable prior year quarter. Production for the nine months of 2012 increased six percent to 1,730 MBoe as compared to 1,634 MBoe produced during the nine months of 2011. The year-over-year production increase was due to increases in overall field production combined with the net positive effect of the acquisition of working interests in the Aneth Field properties from an affiliate of Denbury Resources Inc. (“Denbury”), in April 2012 and the sale of working interests to NNOGC in July 2012.

Wyoming production during the third quarter decreased 6 MBoe, to 133 MBoe from the 139 MBoe produced in the third quarter of 2011, and decreased 37 MBoe during the nine months of 2012, to 424 MBoe from the 461 MBoe produced during the nine months of 2011. The decline in year-over-year production was the result of normal production declines, the sale of non-strategic properties that were producing during the first five months of 2011 and the shut-in of all coalbed methane production during December 2011.

During the third quarter of 2012, production from the Company’s North Dakota properties increased by 66 MBoe, to 85 MBoe, as compared to the 19 MBoe produced in the third quarter of 2011. During the nine months of 2012, production increased 160 MBoe, to 204 MBoe from the 44 MBoe produced during the nine months of 2011. The production increases were the result of more wells on production versus the prior year period.

Production from the Company’s Permian Basin properties during the third quarter increased 29 MBoe, to 55 MBoe from 26 MBoe, during the comparable prior year quarter, and increased 98 MBoe to 124 MBoe for the nine months of 2012 as compared to 26 MBoe for the nine months of 2011. These increases were due to more producing wells in 2012 versus 2011.

Revenue: During the third quarter of 2012, Resolute realized a 29 percent increase in adjusted revenue (revenue net of realized derivatives losses) as compared to the prior year quarter. Total adjusted revenue for the quarter was $60.1 million, including the effect of realized derivative losses of $3.3 million. During the third quarter of 2011, Resolute had total adjusted revenue of $46.7 million, including realized derivative losses of $7.4 million which also included a one-time $5.0 million charge related to the partial termination of certain 2012 derivative contracts.

For the nine months ended September 30, 2012, Resolute realized a fourteen percent increase in adjusted revenue as compared to the nine months of 2011, as increased production continued to drive revenue as oil prices have remained relatively constant. Total adjusted revenue for the nine months of 2012 was $170.4 million, including realized derivative losses of $21.0 million (including $3.4 million of early derivative instrument terminations). For the nine months of 2011, Resolute had total adjusted revenue of $149.9 million, including realized derivative losses of $18.1 million which included a $5.0 million charge related to the partial termination of certain 2012 derivative contracts in the third quarter of 2011.

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Operating Expenses: For the third quarter of 2012, total lease operating expenses increased 45 percent to $21.3 million, or $24.75 per Boe, as compared to third quarter 2011 lease operating expenses of $14.8 million, or $20.25 per Boe. Sequentially, however, total lease operating expenses increased nine percent, from $22.81 per Boe during the preceding quarter. The comparative quarterly increase was mainly due to repair and maintenance activity in Aneth Field to reduce well downtime and increase overall longer-term production and increased activity levels in North Dakota and Texas compared to 2011, which have led to increased operating costs. Total production taxes increased by $0.8 million, or eleven percent, to $8.4 million, or $9.77 per Boe (thirteen percent of revenue), as compared to $7.6 million, or $10.42 per Boe during 2011 (fourteen percent of revenue). This decrease was attributable to the receipt of enhanced oil recovery credits in the Aneth Field Properties during the third quarter of 2012.

For the first nine months of 2012, total lease operating expenses increased 36 percent, to $58.0 million, from 2011 lease operating expenses of $42.7 million, and increased on a per-Boe basis, to $23.40 per Boe in 2012 from $19.71 per Boe in 2011. The comparative nine month increase in lease operating expenses was attributable to the net increase in working interest ownership related to the Denbury acquisition and NNOGC divestiture transactions in the Aneth Field properties in addition to the reasons outlined above. Total production taxes increased by $4.7 million, or twenty percent, to $28.3 million, or $11.40 per Boe (fifteen percent of revenue), as compared to $23.6 million, or $10.91 per Boe for the nine months of 2011 (fourteen percent of revenue). The higher total production taxes were due to higher production volumes combined with higher ad valorem estimates resulting from increases in the assessed value of reserves in 2012.

General and Administrative Expense. Resolute incurred general and administrative expense for the third quarter of 2012 of $6.7 million, as compared to $5.5 million during 2011. On a unit basis, costs increased $0.24, or 3%, from $7.50 during the prior year period. Sequentially, general and administrative expense increased from $5.7 million due to increased labor costs, professional services, share based compensation expense, corporate overhead and other miscellaneous expenses. Cash-based general and administrative expense was $4.1 million, or $4.77 per Boe in 2012, compared to $3.5 million, or $4.73 per Boe in 2011. Stock-based compensation expense, a non-cash item, represented $2.6 million, or $2.97 per Boe, for the third quarter of 2012 and $2.0 million, or $2.77 per Boe, for the third quarter of 2011.

General and administrative expense for the nine months of 2012 was $17.6 million, or $7.08 per Boe, as compared to $14.6 million, or $6.73 per Boe, during the first nine months of 2011. The increase is primarily due to salaries and wages related to hiring to meet the demands of increased operating activities and the reasons noted above. Cash-based general and administrative expense was $11.2 million, or $4.52 per Boe in 2012, compared to $9.2 million, or $4.24 per Boe in 2011. Stock-based compensation expense represented $6.4 million, or $2.56 per Boe, for the first nine months of 2012 and $5.4 million, or $2.49 per Boe, for the first nine months of 2011.

Liquidity and Capital Resources. Outstanding indebtedness at September 30, 2012, consisted of $250 million of senior notes issued during the second quarter and $18 million outstanding on the Company’s revolving credit line.

Capital Expenditures: During the three and nine months ended September 30, 2012, Resolute incurred capital expenditures of approximately $59.3 million and $162.2 million, respectively. Such capital investments were made to support the Company’s ongoing tertiary recovery projects in Greater Aneth Field, to drill fifteen wells and complete 24 wells in North Dakota, to drill five wells and complete thirteen wells in Texas and to expand gas distribution and electrical power infrastructure in the Permian Basin. The year-to-date capital expenditures exclude $37.7 million related to the acquisition of Denbury’s interests in Greater Aneth Field during the second quarter and also exclude $49.5 million received as part of the sales of working interest in the Aneth Field Properties to NNOGC.

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RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Operations (UNAUDITED)

(in thousands, except per share data)

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Reconciliation of Net Income 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, unrealized gains and losses on derivatives, gains and losses on the sale of assets, change in derivative fair value 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 to Adjusted EBITDA.

Earnings Call Information

Resolute will host an investor call on Monday, November 5, 2012, at 5:00 PM ET. To participate in the call please dial (877) 491-0104 from the United States, or (949) 484-0323 from outside the U.S. The conference call I.D. number is 5951 7275. Participants should dial in 5 to 10 minutes before the scheduled time and must be on a touch-tone telephone to ask questions.

A replay of the call will be available through November 8, 2012, by dialing (855) 859-2056 from the U.S., or (404) 537-3406 from outside the U.S. The conference call I.D. number is 2246 6727.

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Forward Looking 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 future financial and operating results; statements regarding our production and cost guidance for 2012 and beyond; future production and reserve growth; the progress of Greater Aneth Field CO₂ flood projects, including CO₂ response times, and additional CO₂ flood potential; anticipated capital expenditures; our operating, development and exploration plans; liquidity and availability of capital; our expectations regarding our development activities including drilling, recompleting and refracing wells and the anticipated timing and costs of such activities; testing and prospectivity of our Bakken and Permian acreage; production from our Aneth Field properties, the Wyoming properties, on our Bakken acreage and from our Permian properties and acreage; and installation of compression, gathering and electrical facilities. 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 volatility of oil and gas prices; inaccuracy in reserve estimates and expected production rates; discovery, estimation, development and replacement of oil and gas reserves; the future cash flow, liquidity and financial position of Resolute; 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; availability and terms of capital; the effectiveness of Resolute’s CO₂ flood program; the potential for downspacing or infill drilling in the Williston Basin of North Dakota 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 in the Bakken trend, the Mowry shale, and Turner and Niobrara formations in Wyoming and the Permian Basin in Texas; potential delays in the completion, commissioning and optimization schedule of Resolute’s gas gathering and facilities construction projects; operating costs and other expenses of Resolute; the success of prospect development and property acquisition of Resolute; 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.; operational problems or uninsured or underinsured losses affecting Resolute’s operations or financial results; government regulation and taxation of the oil and gas industry, including the potential for increased regulation of underground injection and fracing operations; changes in derivatives regulation; developments in oil-producing and gas-producing countries; Resolute’s relationship with the Navajo Nation and the local Navajo community in the area in which Resolute operates; and the success of strategic plans, expectations and objectives for future operations of Resolute. 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 Item 1A.—Risk Factors and all other disclosures appearing in the Company’s Form 10-K for the year ended December 31, 2011 and the Form 10-Q for the quarter ended March 31, 2012 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.

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About Resolute Energy Corporation

Resolute is an independent oil and gas company focused on the acquisition, exploration, exploitation and development of oil and gas properties, with a particular emphasis on liquids-focused, long-lived onshore U.S. opportunities. Resolute’s producing properties are located in the Paradox Basin in Utah, the Powder River Basin in Wyoming, the Permian Basin in Texas and the Bakken trend of North Dakota. The Company also owns exploration and exploitation properties in the Permian Basin of Texas and the Big Horn and Powder River Basins of Wyoming.

# # #

Contact:

HB Juengling

Vice President—Investor Relations

Resolute Energy Corporation

303-534-4600

hbjuengling@resoluteenergy.com

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