2014

Resolute Energy Corporation Announces Results For The Quarter And Full Year Ended December 31, 2013, And Provides Guidance For 2014 - Increased revenue 35 percent and increased Adjusted EBITDA 48 percent year-over-year

- Increased production 31 percent year-over-year and 10 percent sequentially

- First Delaware Basin horizontal well in Reeves County, Texas, had 24-hour peak production rate of 1,403 Boe per day

- First Turner/Frontier horizontal well in Hilight Field, Powder River Basin, reported an average 90 day production rate of 723 Boe per day, 44 Boe per day higher than its 30 day average production rate

DENVER, March 10, 2014 /PRNewswire/ -- Resolute Energy Corporation ("Resolute" or the "Company") (NYSE: REN) today reported financial and operating results for the period ended December 31, 2013, and provided guidance for 2014.

Nicholas Sutton, Chief Executive Officer, said: "We have confirmed the value of our asset positions in the Permian Basin and the Powder River Basin by delivering horizontal well results that meet or exceed our expectations.  In the Delaware portion of the Permian Basin, in Reeves County, Texas, we have drilled two horizontal wells and are drilling a third well.  The first of those wells, the LH Meeker C21 1501H, continues to flow and had a 24-hour peak IP ("IP24") of 1,403 barrels of oil equivalent ("Boe") per day and an initial 30-day IP ("IP30") averaging 1,074 Boe per day (based on three-stream calculation).  Production is from the Wolfcamp A interval and is approximately 48 percent oil.  Because we had infrastructure already built in the area, we were able to put the well on production, including gas flowing into the sales line, within a matter of days after we concluded completion activities.  Our second well, the James 02 1401H, is waiting on completion and the third well, the Harrison State C20 1401H, is nearing total depth.  Our current focus is on the Wolfcamp A and B intervals and we are monitoring activity in the area targeting additional zones in the Wolfcamp and Bone Spring horizons.  The majority of our 28,200 gross (12,800 net) acres in Reeves County are concentrated, which will allow us to operate most of the wells that we plan to drill. 

"We previously have discussed our optimism for horizontal drilling to the Turner/Frontier formation in our Hilight Field in the Powder River Basin, where we have approximately 47,400 acres, all held by production.  In our operations release on December 10, 2013, we announced an IP30 rate of 679 Boe per day from our first Turner/Frontier well, the Castle 3-21TH. Based on recent production data, the Castle well is materially exceeding our expectations, with a 763 Boe per day 60-day average and a 90-day average of 723 Boe per day.  Production is 81 percent crude oil. The well produced approximately 65,000 Boe during its first 90 days of production and our current, admittedly early, estimate of EUR is more than 500 thousand Boe ("MBoe"). Based on extensive well control and interpretation of our 3D seismic, we may have up to 48 Turner/Frontier drilling locations on our acreage.

"You will recall that in our December operations update we discussed results from our three Gardendale horizontal wells in the Midland Basin, producing from the Wolfcamp B.  At that time, we announced an initial IP24 for the Munn-Clark 2617H well of 600 Boe per day.  Subsequently, the Munn-Clark produced 877 Boe during a 24-hour period and had a 30-day average rate of 465 Boe per day (94 percent oil). The Gardendale wells on average continue to produce generally in line with our type curve, showing an EUR of approximately 350 to 400 MBoe per well.  

"We currently have a 9,000 gross (6,800 net) acre position in the Midland Basin.  Our own wells and the results of other operators continue to de-risk our operated acreage in Midland and Ector counties as successful wells have been productive from the Wolfcamp A, B and D (Cline), and middle and lower Spraberry intervals.  In addition, our operated and non-operated acreage in Howard County, Texas, is strategically situated for the emerging horizontal Wolfcamp play moving into the eastern portion of the Midland Basin.

"Our drilling inventory in the Permian and Powder River Basins is more than 460 wells using what we believe is a modest estimate of the number of formations that will ultimately produce and spacing that is considered conservative. As we evaluate the potential for additional zones our well count could increase significantly.  During 2014, we will continue to delineate and prove up our acreage by further horizontal drilling.

"As a final operational note, Aneth Field continues to produce at expectation, notwithstanding severe winter weather considerations. This giant oil field will continue to generate stable oil production and revenue for a long time to come.

"Looking at our year-end financial results, we were generally pleased by our operating metrics.  Production, revenue and Adjusted EBITDA (a non-GAAP measure, reconciled below to net income) were all up significantly year-over-year and sequentially.  Our earnings, however, were materially negatively affected by required implementation of the SEC's "five-year rule" regarding proved undeveloped properties.  That rule requires that undeveloped reserves be developed within five years from when they were first "put on the books" or taken out of the proved reserve base if they have not been developed.  Several high value, high rate of return projects in Aneth Field, such as the membrane plant, further expansion of Aneth Unit Phase 4, and certain aspects of the Desert Creek IIC expansion, while excellent projects, must compete for capital with our horizontal drilling program. As a result, management cannot in good faith certify that they will be developed within the requisite time frame. Removing these projects from our proved reserve base required us to write down the proved asset pool, resulting in the reported non-cash impairment charge to earnings. It is important to note that those projects and assets have not disappeared, and are no more and no less viable and valuable today than they were a month ago.  It's just that under this relatively new SEC rule the associated reserves are now categorized as probable rather than proved.

"Looking ahead, in light of our horizontal drilling success and the Company's large opportunity inventory, Resolute's management team is investigating various financing options that will enable the Company to accelerate its horizontal program.  More to come on this topic as our plans become more definite."

Operations Update

Permian Basin

In the fourth quarter of 2013, Resolute initiated its horizontal drilling program and to date has completed three Wolfcamp B horizontal wells in the Gardendale area of the Midland Basin.  The results of these wells were discussed in our December operational update.  To build on the successful transition to horizontal wells, the rig moved to Reeves County in the Delaware Basin, where it spud the LH Meeker C21 1501H in late October to test the Wolfcamp A. The well was completed on January 15 and is still flowing naturally at a high surface pressure. Thus far, production has achieved a peak IP24 rate of 1,403 Boe per day and an IP30 rate of 1,074 Boe per day, of which 49 percent was oil.  The drilling rig then moved to the James 2 1401H which has reached total depth in the Wolfcamp formation and is waiting on completion. The rig is currently drilling our third horizontal well in Reeves County, the Harrison State C20 1401H. 

Resolute also participated as an eleven percent working interest owner in another Reeves County horizontal well, the Red Rock 6-6 #1H operated by Energen Resources Corporation.  Energen reported an IP24 of 1,471 Boe per day and IP30 of 1,137 Boe per day (64 percent oil).  In the Midland Basin, we partnered with two other operators on our Big Spring acreage block where we drilled and completed three vertical wells.  Resolute has an average 49 percent working interest in those three wells, and production on average exceeds our pre-drill expectations.

In our Denton Field in Lea County, New Mexico, we collected 3D seismic over our acreage to help identify opportunities to increase production from that old but prolific field. The 3D seismic data will be processed and interpreted during the first half of 2014.

Hilight Field – Powder River Basin

The Castle 3-21TH, our first Turner/Frontier horizontal well has been on production for more than a quarter, and we now can report that it averaged 723 Boe per day (81 percent oil) during the first ninety days of production.  Interestingly, the production profile has been relatively flat during that period.  We had infrastructure in place, so the well went into production very quickly.  As noted previously, we believe that we have as many as 48 Turner/Frontier drilling locations on our Hilight Field acreage, and also point out that the Powder River Basin is an increasingly active province for exploration and development of shallower intervals, including the Parkman, Shannon, Sussex, and Niobrara formations.  Near term, horizontal wells in the Turner/Frontier formation will drive Hilight production growth and we are building a permit inventory to enable the transition to a full time drilling program.

Aneth Field

Year-over-year production from Aneth Field was essentially flat, with a five percent increase in gross production offset by the sale of certain interests to Navajo Nation Oil and Gas Company ("NNOGC").  In addition, a pipeline issue caused gas sales to be shut-in for nine months of the year.  Severe cold weather hampered production in fourth quarter and appears to have been a causative factor in a number of down-hole failures. We also faced delays in permitting that forced us to defer implementation of certain capital projects.  As a result, approximately $13 million of capital previously earmarked for Aneth was redeployed to the Permian Basin and Powder River Basin horizontal drilling activities.

On a more positive note, three new wells were brought on production in Aneth Field in the fourth quarter.  The Aneth Unit C-123X reached an IP90 of 207 Boe per day (100 percent oil, since all produced gas is re-injected), with a current production of 197 Boe per day.  In the Ratherford Unit, the 20-42H produced an IP30 of 234 Boe per day (88 percent oil) with a current production of 102 Boe per day (94 percent oil) and the 24-32H produced an IP90 of 72 Boe per day (72 percent oil) with a current rate of 73 Boe per day (89 percent oil).  Additionally, three new wells have been put on injection since the end of the fourth quarter; two in the Aneth Unit and one in the Ratherford Unit. We also installed and commissioned additional compression, which will allow us to process more fluids, thereby increasing oil production. We commissioned a portion of the Greater Aneth electrical substation, installed additional electrical capacitance and signed an agreement to increase our electrical power availability.  All of these things will serve to enhance Aneth Field reliability. 

Fourth Quarter and Annual Comparative Results

During the quarter ended December 31, 2013, Resolute recorded a net loss of $117.1 million, or ($1.60) per share, on revenue of $92.7 million.  This compares to a net loss of $1.6 million, or $(0.03) per share, on revenue of $66.9 million in the fourth quarter of 2012. Included in the 2013 loss was a $188 million impairment of proved oil and gas properties pursuant to the full-cost ceiling test, primarily from removal of certain Proved Undeveloped reserves pursuant to the SEC's "five-year rule," as discussed previously.

During 2013, Resolute recorded a net loss of $113.8 million or ($1.67) per share, on revenue of $349.8 million.  This compares to net income of $18.0 million, or $0.30 per diluted share for the 2012 period, on revenue of $258.3 million.

Fourth Quarter and Annual 2013 Results Compared to Fourth Quarter
and Annual 2012 Results














Three Months Ended December 31, 


Twelve Months Ended December 31, 


2013

2012


2013

2012


($ thousands, except per-Boe amounts)

Production (MBoe):






  Aneth

581

593


2,246

2,323

  Permian

423

84


1,442

207

  Wyoming

161

139


571

564

  North Dakota

4

111


208

315

Total production

1,169

927


4,467

3,409







Daily rate (Boe)

12,709

10,073


12,239

9,313







Revenue per Boe (excluding commodity

 derivative settlements)

$      79.27

$      72.15


$         78.30

$            75.77

Revenue per Boe (including commodity derivative settlements) 1

$      79.11

$      70.10


$         70.28

$            69.05







Revenue

$    92,681

$    66,856


$     349,779

$        258,268

Commodity derivative losses 1

(187)

(1,900)


(35,813)

(22,920)

Revenue, net of derivative losses

92,494

64,956


313,966

235,348







Operating expenses:






  Lease operating expense

27,328

21,849


103,276

79,922

  Production and ad valorem taxes

9,931

7,428


40,402

35,716

  Depletion, depreciation, amortization   and asset retirement obligation   accretion

35,992

22,798


116,344

78,414

  Impairment of proved oil and gas   properties

188,000

-


188,000

-

  General and administrative expense 

9,067

6,452


35,625

24,032







Net income (loss)

$   (117,106)

$      (1,625)


$     (113,806)

$          17,976







Adjusted EBITDA

$       50,588

$      31,758


$       160,350

$        108,511







1The twelve months ended December 31, 2013, includes a $10.7 million charge to restructure or terminate certain 2013 commodity derivative contracts. The twelve months ended December 31, 2012, includes a charge of $3.4 million related to the early termination of certain 2012 commodity derivative contracts.

 

Adjusted EBITDA (a non-GAAP measure): During the fourth quarter of 2013, Resolute generated $50.6 million of Adjusted EBITDA, or $43.27 per Boe, a 59 percent increase from the prior year period during which Resolute generated $31.8 million of Adjusted EBITDA, or $34.27 per Boe.  The increase in Adjusted EBITDA resulted primarily from increased commodity pricing ($79.27 per Boe in 2013 compared to $72.15 per Boe in 2012) and increased production related to wells drilled in Texas and wells acquired in December 2012 and March 2013 in the Permian Basin.  The production increase was offset partially by the sale of the Company's New Home assets in North Dakota and certain working interests to NNOGC. 

During 2013, Resolute generated $160.4 million of Adjusted EBITDA, or $35.89 per Boe, a 48 percent increase from the prior year period.  During the comparable prior year period, Resolute generated $108.5 million of Adjusted EBITDA, or $31.83 per Boe.  The reasons for the annual increase were substantially the same as those discussed for the quarterly increase.

Production:  Production for the quarter ended December 31, 2013, increased 26 percent to 1,169 MBoe as compared to 927 MBoe during the fourth quarter of 2012, and increased ten percent from the third quarter of 2013.  Production for 2013 was 4,467 MBoe as compared to 3,409 MBoe during 2012, an increase of 31 percent, or 1,058 MBoe.

Fourth quarter production from the Company's Aneth Field properties decreased two percent, to 581 MBoe from 593 MBoe, from that of the comparable prior year quarter, and decreased three percent to 2,246 MBoe for 2013 as compared to 2,323 MBoe during 2012.  The production decrease was principally attributable to the sale of Aneth Field interests in January 2013 to NNOGC, the gas sales impact of the pipeline shut-in at Aneth Field and CO2 injection curtailments.

Production from the Company's Permian Basin properties increased by 339 MBoe, to 423 MBoe, as compared to the 84 MBoe produced in the fourth quarter of 2012. During 2013, production increased 1,235 MBoe, to 1,442 MBoe from the 207 MBoe produced during 2012.  These increases were attributable to the acquisition of producing wells in the Permian Basin in December 2012 and March 2013 and to the Company's drilling activity in the area.

Wyoming production during the fourth quarter increased 22 MBoe to 161 MBoe from the 139 MBoe produced in the fourth quarter of 2012, and increased 7 MBoe during 2013, to 571 MBoe from the 564 MBoe produced during 2012.  The increase in year-over-year production is the result of successfully completing a horizontal well in the Turner/Frontier formation in the fourth quarter of 2013.

During the fourth quarter of 2013, production from the Company's North Dakota properties decreased by 107 MBoe, to 4 MBoe, as compared to the 111 MBoe produced in the fourth quarter of 2012.  During 2013, production decreased from 315 MBoe in 2012 to 208 MBoe in 2013.  The decrease in production was the result of the disposition of the New Home Properties, which closed on July 15, 2013.

Revenue:  During the fourth quarter of 2013, Resolute realized a 42 percent increase in adjusted revenue (revenue net of commodity derivative settlement losses) as compared to the prior year quarter due to revenue associated with increased commodity prices as well as increased production.  Total adjusted revenue for the quarter was $92.5 million, including the effect of commodity derivative settlement losses of $0.2 million.  During the fourth quarter of 2012, Resolute had total adjusted revenue of $65.0 million.

During 2013, Resolute realized a 33 percent increase in adjusted revenue as compared to 2012, due to increased commodity prices and production.  Total adjusted revenue for 2013 was $314.0 million, including commodity derivative settlement losses of $35.8 million (including $10.7 million paid to restructure or terminate certain 2013 commodity derivative contracts).  For 2012, Resolute had total adjusted revenue of $235.3 million, including commodity derivative settlement losses of $22.9 million ($3.4 million of which was related to early commodity derivative instrument terminations).

Operating Expenses:  For the fourth quarter of 2013, total lease operating expenses ("LOE") increased 25 percent to $27.3 million as compared to fourth quarter 2012 LOE of $21.8 million, but decreased one percent on a per-Boe basis from $23.58 per Boe during 2012 to $23.37 per Boe during 2013.  Sequentially, LOE increased nine percent, but decreased on a per-Boe basis to $23.37 per Boe from $23.76 per Boe during the preceding quarter. The quarter-over-quarter aggregate dollar increase was mainly attributable to expanded operational activity in the Permian Basin. Total production taxes increased by $2.5 million, or 34 percent, to $9.9 million (eleven percent of revenue) from $7.4 million in 2012 (eleven percent of revenue), and increased on a Boe basis from $8.02 per Boe in 2012 to $8.49 per Boe in 2013 due to higher product pricing.

During 2013, total LOE increased 29 percent, to $103.3 million, from 2012 LOE of $79.9 million, but decreased on a Boe basis from $23.45 per Boe in 2012 to $23.12 per Boe in 2013.  Total production taxes increased by $4.7 million, or thirteen percent, to $40.4 million (twelve percent of revenue) as compared to $35.7 million (fourteen percent of revenue), but decreased on a per-Boe basis from $10.48 per Boe in 2012 to $9.04 per Boe in 2013.  The per-Boe decrease in LOE and production taxes from the comparative period in 2012 reflects the operational shift to lower cost production areas in the Permian Basin, somewhat offset by the impact of higher product pricing.  In addition, the Company's ad valorem taxes in Aneth Field decreased compared to 2012 due to lower tax assessments in 2013.

For the fourth quarter of 2013, depletion, depreciation, amortization and accretion expenses increased 58 percent to $36.0 million, or $30.78 per Boe, as compared to $22.8 million, or $24.60 per Boe during the fourth quarter of 2012. Depletion, depreciation, amortization and accretion expenses during 2013 increased 48 percent to $116.3 million, or $26.04 per Boe, as compared to $78.4 million, or $23.00 per Boe during 2012. The increase was principally driven by a higher depletion rate due to a year-over-year decrease in proved reserves, a higher depletable base, higher finding costs and increased production during 2013.

Impairment of Proved Oil and Gas Properties: As previously discussed, pursuant to full cost accounting rules, we perform a ceiling test each quarter on our proved oil and gas assets.  We recorded a $188 million non-cash impairment of the carrying value of our proved oil and gas properties at December 31, 2013, primarily resulting from the "five-year rule."  No impairment was recorded during 2012.

General and Administrative Expense:  Resolute incurred general and administrative expense for the fourth quarter of 2013 of $9.1 million, or $7.75 per Boe, as compared to general and administrative expense of $6.5 million, or $6.96 per Boe, during 2012 and $8.37 per Boe in the preceding quarter.  The aggregate and per Boe year-over-year increases resulted from increased salaries and wages, including share-based compensation, necessary to meet growth demands and increased professional service costs largely associated with the Permian Basin acquisitions in December 2012 and March 2013.  Cash-based general and administrative expense was $4.9 million, or $4.16 per Boe in 2013, compared to $4.1 million, or $4.41 per Boe in 2012.  Stock-based compensation expense, non-cash item, represented $4.2 million, or $3.59 per Boe, for the fourth quarter of 2013 and $2.4 million, or $2.55 per Boe, for the fourth quarter of 2012.

General and administrative expense during 2013 was $35.6 million, or $7.97 per Boe, as compared to general and administrative expense of $24.0 million, or $7.05 per Boe, during 2012 due to the reasons noted above.  Cash-based general and administrative expense was $21.7 million or $4.85 per Boe in 2013, compared to $15.3 million, or $4.49 per Boe in 2012.  Stock-based compensation expense represented $14.0 million, or $3.13 per Boe, during 2013 and $8.7 million, or $2.56 per Boe, during 2012.

Capital Expenditures:  During 2013, Resolute incurred oil and gas related capital expenditures of approximately $237 million.  These capital investments were directed principally toward the Company's ongoing tertiary recovery and drilling projects in Aneth Field and drilling and completion projects in the Permian Basin, the Powder River Basin and the Bakken trend in North Dakota.  Those field-level capital expenditures exclude $290 million of net acquisitions and divestitures and other corporate capital.  Capital expenditures were financed by operating cash flow, borrowings under the Company's revolving credit facility, cash on hand, proceeds from the sale of assets in Aneth Field to NNOGC, proceeds from the sale of the New Home Properties in North Dakota and the issuance of equity securities.

Liquidity and Capital Resources: Outstanding indebtedness at December 31, 2013, consisted of $400 million of senior notes and $335 million in credit facility debt.  During the second quarter of 2013, the Company sold 13.3 million shares of common stock in a public offering at $8.00 per share and received approximately $101.8 million in net proceeds, after underwriting discounts and commissions. In connection with the equity offering, the $40 million non-conforming tranche of the borrowing base on the credit facility was automatically terminated, thereby reducing the borrowing base from $485 million to $445 million.  In July 2013, as a result of the disposition of the New Home Properties, the borrowing base under the Company's revolving credit facility was adjusted downward by $30 million to $415 million.  Proceeds from that sale were used to reduce amounts outstanding under the Company's revolving credit facility. 

On March 7, 2014, the Company entered into the Ninth Amendment to the amended and restated Credit Facility which redefined and adjusted the Maximum Leverage Ratio to (a) 4.90:1.00 for the fiscal quarters ending March 31, 2014 and June 30, 2014, (b) 4.75:1.00 for the fiscal quarters ending September 30, 2014 and December 31, 2014, and (c) 4.00:1.00 for all quarters thereafter.  The Ninth Amendment also provided that as of the last day of each fiscal quarter in 2014, the ratio of senior secured debt as of such date to Adjusted EBITDA for the four quarter period ending on such date may not exceed 2.75:1.00.

At February 28, 2014, we had approximately $80 million of liquidity, including cash on hand and amounts available under our credit facility. This liquidity, plus our cash flow from operations, should provide the Company the ability to fund its 2014 capital plan described below.  In addition, as noted previously, management is actively evaluating financing options that would allow the Company to significantly accelerate its horizontal activities in the Permian and Powder River basins.

2014 Capital Budget and Guidance

The following guidance is subject in its entirety to all the cautionary statements and qualifications described below and under the caption "Cautionary Statements." 

Resolute has established a 2014 Base Operating and Financial Plan ("Base Plan") that purposely limits the Company's activities to those that we expect will generate the highest overall improvements in operating and financial metrics, meet operational constraints and considerations, such as lease terms, and limit cash expenditures to a  maximum of available cash flow. The Base Plan allocates more capital to drilling horizontal wells in the Permian and Powder River basins, which have higher expected rates of return, and less capital to development projects in Aneth Field. The Base Plan is designed to hold debt to current levels while still allowing the Company to continue with its horizontal drilling at a moderate pace. However, management is actively evaluating financial options that would allow the Company to accelerate its high value horizontal drilling activities.  The data set forth below are based on the Base Plan.

Capital Expenditures:  Resolute expects to invest between $136 million and $153 million in 2014 for its base development activities, including drilling and completions, facilities construction and upgrades, leasing and other corporate capital.  The Company intends to fund 2014 capital expenditures substantially from internally generated cash flow. 

Resolute will evaluate its capital expenditures in relation to its cash flow and may adjust its activity and capital spending levels based on changes in commodity prices, the cost of goods and services, production results and other considerations.

Production:  The Company estimates that full-year production for 2014 will be between 4.5 million Boe ("MMBoe") and 4.9 MMBoe.  The midpoint of 2014 production guidance represents a five percent increase from full-year 2013 production of 4.47 MMBoe.  On a revenue-weighted basis, approximately 93 percent of Resolute's production is expected to come from sales of oil and natural gas liquids ("NGL"), while on a volume-weighted basis approximately 82 percent is expected to be attributed to oil and NGL.

Lease Operating Expense:  Resolute projects annual cash LOE for 2014 to be between $98 million and $113 million.  This results in a slight reduction in per-unit LOE in 2014 when compared to 2013.  Production taxes are expected to be twelve to twelve and one half percent of 2014 production revenue. 

General & Administrative Expense:  Resolute anticipates that annual net general and administrative expense for 2014 will be between $25 million and $30 million, excluding non-cash stock-based compensation expense.  The increase in general and administrative expense relative to 2013 is substantially related to increased staffing necessary to support our expanded operations in the Permian Basin as well as the full-year effect of the personnel additions which occurred during the course of 2013.

Depletion, Depreciation and Amortization:  Resolute anticipates that its depletion, depreciation and amortization rate for full year 2014 will be between $29.00 and $31.00 per Boe of production.  The increase from 2013 is substantially a result of the write down of Proved Undeveloped reserve quantities necessitated by implementation of the SEC "five-year rule" discussed elsewhere in this release.

The following table summarizes Resolute's current financial and operational estimates for the full year 2014.


Range



Projected 2014 total production (MBoe)

4,525 – 4,890

Boe per day

12,400 – 13,400

On a revenue-basis:


Oil

91%

Oil and NGL

93%

On a volume-weighted basis:


Oil

77%

Oil and NGL

82%





Projected 2014 costs


Lease operating expense ($ million)

$98 - $113

General and administrative ($ million)

$25 - $30

Production and related taxes (% of production revenue)

12.0% - 12.5%

Depletion, depreciation and amortization ($ per Boe)

$29.00 - $31.00



Projected 2014 capital expenditures ($ million)

$136 - $153

Aneth (excluding CO2)

$18 - $20

Aneth CO2

Permian Basin

$16 - $18

$70 - $77

Powder River Basin

$12 - $14

Leasing and other

 

$20 - $24

 



Hedging Activities

Resolute has commodity derivatives in place for 2014 covering aggregate average daily oil volumes of 7,700 barrels of oil per day ("Bbl per day").  Of that volume, 71 percent (5,500 Bbl per day) is covered by swaps with an average strike price of $92.94, 16 percent (1,200 Bbl per day) is covered by a put spread with purchased and sold strike prices of $85.00 per Bbl and $70.00 per Bbl, respectively, with the remaining volumes (1,000 Bbl per day) covered by a three-way collar with a cap of $95.00 per Bbl, a floor of $80.00 per Bbl, and a sold put option of $70.00 per Bbl.  A NYMEX weighted average price of $90.00 per Bbl would yield a weighted average price to the Company of $91.66 per Bbl.  The Company also has in place swaps covering daily gas volumes of 5,000 million British thermal units ("MMBtu") per day at NYMEX weighted average prices of $4.17 per MMBtu.

Year-End 2013 Proved Reserves and Additional Resource Potential

At December 31, 2013, Resolute's estimated proved reserves were 59.4 MMBoe, compared to year-end 2012 proved reserves of 78.8 MMBoe.  Approximately 80 percent of the Company's 2013 year-end proved reserves were classified as oil and 88 percent were liquids.  Undeveloped reserves comprise 21 percent of total proved reserves. 

The pre-tax present value of the Company's estimated future net revenues from Proved Reserves, a non-GAAP financial measure, was estimated to be $1.1 billion as of December 31, 2013, using Securities and Exchange Commission pricing guidelines for year-end 2013 discounted at 10 percent ("PV10").  The year-end pricing used in calculating the present value averaged $96.94 per barrel of oil and $3.67 per MMBtu of natural gas (as adjusted for differentials and natural gas liquids content, and excluding the impact of existing hedges).

The downward revision of 19 MMBoe to Proved Reserves is comprised of a reduction to Proved Undeveloped reserves of approximately 25 MMBoe, due largely to the effect of the SEC "five year rule", offset by an upward adjustment of approximately 6 MMBoe related to purchases, production and other revisions.  The deferred projects will be eligible for classification as Proved Undeveloped reserves at such time as management adopts a definitive plan to complete the projects.  The reduction has almost no impact on near-term production or cash flow profile.

In 2013, the Company added approximately 13.6 MMBoe of proved reserves from operational activities and reserve acquisitions.  This increase was offset by production of 4.5 MMBoe and 5.9 MMBoe related to sales of our Bakken and certain working interests in our Aneth Field properties.

Beyond our Proved Reserve base, our additional resource potential is estimated to be 100 MMBoe to 325 MMBoe. Resources include volumes from Proved Undeveloped reserves that were removed from our 2013 reserve report and our current assessment of the range of net resource potential in our existing asset base.

RESOLUTE ENERGY CORPORATION


Consolidated Statements of Operations

(in thousands, except per share data)






Year-Ended December 31,

Revenue:

2013

2012

2011

  Oil

$       321,047

$       240,444

$         203,876

  Gas

21,444

16,289

19,376

  Natural gas liquids

7,288

1,535

3,656

     Total revenue

349,779

258,268

226,908

Operating expenses:




Lease operating

103,276

79,922

59,516

Production and ad valorem taxes

40,402

35,716

31,379

Depletion, depreciation, amortization and asset retirement

obligation accretion

116,344

78,414

57,664

Impairment of proved oil and gas properties

188,000

General and administrative

35,625

24,032

20,914

Total operating expenses

483,647

218,084

169,473

Income (loss) from operations

(133,868)

40,184

57,435

Other income (expense):




Interest expense, net

(29,302)

(15,523)

(3,844)

Commodity derivative instruments gain (loss)

(15,336)

5,176

(5,321)

Other income

21

20

85

Total other expense

(44,617)

(10,327)

(9,080)

Income (loss) before income taxes

(178,485)

29,857

48,355

Income tax benefit (expense)

64,679

(11,881)

(17,870)

Net income (loss)

$     (113,806)

$          17,976

$           30,485





Net income (loss) per common share:




Basic

$            (1.67)

$              0.30

$                0.53

Diluted

$            (1.67)

$              0.30

$                0.47

Weighted average common shares outstanding:




Basic

68,260

59,424

57,612

Diluted

68,260

59,452

65,029





 

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, mark-to-market commodity derivative gain (loss), early commodity derivative settlements, 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 (loss) to Adjusted EBITDA. 

 


 Three Months Ended December 31,

Twelve Months Ended December 31,


2013

2012

2013

2012


($ in thousands)






Net income (loss)

$    (117,106)

$         (1,625)

$    (113,806)

$        17,976






Adjustments:





Interest expense

7,277

6,014

29,302

15,523

Tax expense (benefit)

(66,637)

208

(64,679)

11,881

Depletion, depreciation, amortization

and accretion

35,992

22,798

116,344

78,414

Stock-based compensation

4,419

2,495

14,924

9,399

Impairment of proved oil and gas

properties

188,000

188,000

Early settlement of derivative contracts

10,741

3,414

Mark-to-market derivative loss (gain)

(1,357)

1,868

(20,476)

(28,096)

Total adjustments

167,694

33,383

274,156

90,535






Adjusted EBITDA

$        50,588

$        31,758

$      160,350

$      108,511











Earnings Call Information

Resolute will host an investor call on March 10, 2014, at 4:30 PM ET. To participate in the call please dial (877) 418-5260 from the United States, or (866) 605-3852 from Canada or (412) 717-9589 from outside the U.S. and Canada. The conference call I.D. number is 1004 0984.  Participants should dial in five to ten 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 March 10, 2014, by dialing (877) 344-7529 from the U.S., or (412) 317-0088 from outside the U.S. The conference call I.D. number is 1004 0984.

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 future financial and operating results; statements regarding our production and cost guidance for 2014; liquidity and availability of capital including projections of free cash flow; future production and reserve growth; estimates of original oil in place, resource potential, decline rates and ultimate recoveries of oil and gas (EUR); anticipated capital expenditures in 2014 and the sources of such funding; our expectations regarding our operating, drilling, development and exploration plans and anticipated costs thereof; our anticipated revenues, lease operating expenses, general and administrative rates, tax rates and DD&A rates; anticipated CO2 injection rates and response; our plans and expectations regarding our development activities including drilling, deepening, recompleting, fracing and refracing wells, the number of such potential projects, drilling locations, and productive intervals, the anticipated timing, cost and rate of return of such activities, and the EURs and resource potential of such projects; and the testing and 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: 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; discovery, estimation, development and replacement 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; 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 Permian Basin of Texas or obstacles thereto; uncertainty surrounding timing of identifying drilling locations and necessary capital to drill such locations; 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; 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.; potential delays in the upgrade of third-party electrical infrastructure serving Aneth Field and potential power supply limitations; 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; risks and uncertainties associated with horizontal drilling and completion techniques; the availability of water and our ability to adequately treat and dispose of water 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 Navajo community in the area in which Resolute operates; the success of strategic plans, expectations and objectives for future operations of Resolute; and Resolute's level of indebtedness including our ability to fulfill our obligations under the senior notes and our credit facility.  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, 2013, 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.

Additionally, the SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmental regulations.  The SEC permits the optional disclosure of probable and possible reserves.  From time to time, we may elect to disclose "probable" reserves and "possible" reserves, excluding their valuation, in our SEC filings, press releases and investor presentations.  The SEC defines "probable" reserves as "those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." The SEC defines "possible" reserves as "those additional reserves that are less certain to be recovered than probable reserves."  The Company applied these definitions when estimating probable and possible reserves.  Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered.  Any reserve estimates or potential resources provided in this press release that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's reserves reporting guidelines. 

The SEC's rules prohibit us from including resource estimates in our public filings with the SEC. Our potential resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves, (ii) other areas to take into account the low level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Potential resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon for such purpose.  Potential resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors.  In our press releases and investor presentations, we sometimes include estimates of quantities of oil and gas using certain terms, such as "resource," "resource potential," "EUR," "oil in place," or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC definition of proved, probable and possible reserves.  These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Resolute. The Company believes its resource estimates are reasonable, but such estimates have not been reviewed by independent engineers.  Furthermore, estimates of resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

Finally, 24 hour peak IP rates and 30 day peak IP 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 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. 

You are urged to consider closely the disclosure in Resolute's Annual Report on Form 10- K filed on March 10, 2014, in particular the factors described under "Risk Factors."

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 Permian Basin in Texas and New Mexico and the Powder River Basin in Wyoming.  The Company also owns exploration 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

SOURCE Resolute Energy Corporation




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