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REN > SEC Filings for REN > Form 10-Q on 5-Nov-2013All Recent SEC Filings

Show all filings for RESOLUTE ENERGY CORP

Form 10-Q for RESOLUTE ENERGY CORP


5-Nov-2013

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in our Annual Report on Form 10-K for the year ended December 31, 2012, as well as the accompanying financial statements and the related notes contained elsewhere in this report. References to "Resolute," "the Company," "we," "ours," and "us" refer to Resolute Energy Corporation and its subsidiaries.

Overview

We are a publicly traded, independent oil and gas company engaged in the exploitation, development, exploration for and acquisition of oil and gas properties. Our asset base is comprised primarily of properties in Aneth Field located in the Paradox Basin in southeast Utah (the "Aneth Field Properties" or "Aneth Field"), the Permian Basin in west Texas and southeast New Mexico (the "Permian Properties") and the Powder River and Big Horn basins in Wyoming (the "Wyoming Properties"). Our primary operational focus is on increasing reserves and production from these properties while improving efficiency and optimizing operating costs. We plan to expand our reserve base through an organic growth strategy focused on the expansion of tertiary oil recovery in Aneth Field, the exploitation and development of oil-prone acreage, particularly in our Permian Properties, and through carefully targeted exploration activities in our Wyoming Properties. We also expect to engage in opportunistic acquisitions.

As of December 31, 2012, our estimated net proved reserves were approximately 78.8 million equivalent barrels of oil ("MMBoe"), of which approximately 59% and 43% were proved developed reserves and proved developed producing reserves, respectively. Approximately 79% of our net proved reserves were oil and approximately 90% were oil and natural gas liquids ("NGL"). The December 31, 2012, pre-tax present value discounted at 10% of our net proved reserves was $1,127 million and the standardized measure of our estimated net proved reserves was $872 million. We focus our efforts on increasing reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flow from existing operations are dependent on a variety of factors including commodity prices, exploitation and recovery activities and our ability to manage our overall cost structure at a level that allows for profitable operation.

Our management uses a variety of financial and operational measurements to analyze our operating performance, including but not limited to, production levels, pricing and cost trends, reserve trends, operating and general and administrative expenses and operating cash flow. The analysis of these measurements should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in our Annual Report on Form 10-K for the year ended December 31, 2012.

Aneth Field Properties

Our largest asset, constituting 75% of our net proved reserves as of December 31, 2012, is our ownership of working interests in Aneth Field, a mature, long-lived oil producing field, most of which is located on the Navajo Reservation in southeast Utah. We own a majority of the working interests in, and are the operator of, three federal production units which constitute the Aneth Field Properties. These are the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit, in which we owned working interests of 62%, 68% and 59%, respectively, at September 30, 2013. The crude oil produced from the Aneth Field Properties is generally characterized as light, sweet crude oil that is highly desired as a refinery blending feedstock. We believe that significantly more oil can be recovered from our Aneth Field Properties through industry standard secondary and tertiary recovery techniques.

During 2012, we and Navajo Nation Oil and Gas Company ("NNOGC") entered into an amendment to our Cooperative Agreement. Among other changes, this amendment allowed NNOGC to exercise options to purchase 10% of our interest in Aneth Field. These options were exercised for cash consideration of $100 million. We entered into a purchase and sale agreement relating to the exercise of the options which provided that the transaction be closed and paid for in two equal transfers, each for 5% of our interest in the properties. The first transfer took place in July 2012 and the second transfer took place in January 2013, each with an effective date of January 1, 2012. We remain the operator of our Aneth Field Properties.

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Permian Properties

On December 21, 2012, we purchased properties from Celero Energy II, LP containing proved reserves of approximately 4.1 MMBoe in Denton Field on the Northwest Shelf in Lea County, New Mexico, and in the Spraberry trend in the Midland Basin portion of the Permian Basin in Howard County, Texas, for a purchase price of approximately $117 million. Additionally, on December 28, 2012, we purchased an undivided 32.35% interest in certain oil and gas properties from RSP Permian, LLC and certain other sellers ("RSP") containing proved reserves of approximately 5.4 MMBoe in the Wolfberry play in the Midland Basin portion of the Permian Basin in Midland and Ector counties, Texas, for a purchase price of approximately $133 million, which included a $6 million fee paid in exchange for the option to acquire the remaining 67.65% interest in the RSP properties. This fee was nonrefundable but would be applied towards the purchase price if the option were exercised. On March 22, 2013, we exercised that option and acquired the remaining 67.65% interest in the RSP properties, which contained proved reserves of approximately 11.1 MMBoe. The purchase price for the 67.65% interest was $258 million, net of the option fee, after customary purchase price adjustments, which were estimated at closing. The RSP acquisitions included approximately 4,700 gross (4,600 net) acres, 80 producing wells and facilities for gathering, water sourcing and water disposal. The acreage is largely held by production, and we estimate that a one-rig vertical drilling program for two years would hold all of the acquired leases. We believe that growth potential exists from approximately 28 gross prospective horizontal locations with multiple targets in the Wolfcamp, Spraberry and Atoka formations, approximately 45 vertical drilling locations targeting the Wolfcamp through Atoka interval, and 69 Spraberry recompletion opportunities. On a combined basis, our December 2012 and March 2013 acquisitions (the "Permian Acquisitions") contributed 20.6 MMBoe of proved reserves as of the effected date of the acqusitions. The Permian Acquisitions were financed with the net proceeds from our $150 million senior notes offering in December 2012 and borrowings under our revolving credit facility.

Our Permian Properties are located in the Permian Basin of west Texas and southeast New Mexico, and are divided between three principal project areas. Our Wolfberry project area, located in the Midland Basin portion of the Permian Basin, in Howard, Martin, Midland and Ector counties, primarily targets the Wolfcamp and Spraberry formations with secondary objectives in the Mississippian, Cline and Dean formations. Our Wolfbone project area, located in the Delaware Basin portion of the Permian Basin, in Reeves County, primarily targets the Wolfcamp and Bone Spring formations. Our third project area, the Northwest Shelf in Lea County, New Mexico, is centered on conventional production in Denton, Gladiola and South Knowles fields where we are focused on improving field-level economics through production enhancements and operating cost reductions. We also believe upside exists in these properties through well deepenings and infill drilling. Historic drilling activity in each of our Wolfberry and Wolfbone project areas has focused on vertical wells with completions in multiple pay zones. Recently the industry has increased its focus on horizontal drilling, primarily in the Wolfcamp formation, as well as the Spraberry and Cline formations in the Midland Basin and the Bone Spring formation in the Delaware Basin. We anticipate that our drilling activity in the Wolfbone and Wolfberry areas will be increasingly focused on horizontal drilling activity targeting these same formations.

During the first nine months of 2013, we completed 29 gross (26.0 net) wells on our Permian Properties. We were in the process of drilling 1 gross (0.1 net) horizontal well and had 5 gross (4.0 net) wells awaiting completion at quarter end, including 2 gross (2.0 net) horizontal wells.

Wyoming Properties

Hilight Field is located in the Powder River Basin in Campbell County, Wyoming. Hilight Field is located in a basin experiencing transformation due to horizontal drilling targeting oil-bearing formations such as the Turner/Frontier, Niobrara and Mowry. Along with these unconventional opportunities, the Powder River Basin continues to see exploration activity targeting the conventional Minnelusa formation. We have focused our geological, geophysical and engineering efforts to prepare for testing these formations. These activities have included a 3D seismic survey of the field and the review of our extensive log data and data from operators drilling wells in close proximity to Hilight. We drilled 1 gross (1.0 net) horizontal well to test the Turner/Frontier formation in the third quarter. This well was awaiting completion at quarter end and is scheduled to begin producing in November 2013. We also plan to develop the Mowry formation through additional uphole recompletions. We anticipate completing the third and final test in the fourth quarter. Our analysis of the Mowry completions will determine whether we can establish a viable horizontal drilling program in this formation. In our exploration portfolio we also own acreage in the Big Horn Basin, which may be prospective for production from multiple formations, including the Frontier and Phosphoria. We continue to study these formations with the objective of testing them prior to facing significant lease expirations in 2015.

Bakken Properties

On June 27, 2013, we entered into a purchase and sale agreement with HRC Energy, LLC, a Colorado limited liability company, and wholly-owned subsidiary of Halcón Resources Corporation, a Delaware corporation, effective March 1, 2013, to dispose of our Bakken properties located in Williams County (the "New Home Properties") for proceeds of $75 million before customary purchase price adjustments. The transaction closed on July 15, 2013. We recorded the net proceeds as a reduction to the capitalized costs of the Company's oil and gas properties. Our remaining Bakken Properties are located in the Bakken trend of the Williston Basin in North Dakota and consist of our Paris project area located in McKenzie County. We also have interests in various smaller project areas, primarily in McKenzie County. During the first nine months of 2013, we completed 9 gross (2.0 net) wells on our Bakken Properties.

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Factors That Significantly Affect Our Financial Results

Revenue, cash flow from operations and future growth depend on many factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historical oil prices have been volatile and are expected to fluctuate widely in the future. Sustained periods of low prices for oil could materially and adversely affect our financial position, our results of operations, the quantities of oil and gas that we can economically produce and our ability to obtain capital.

Like all businesses engaged in the exploration for and production of oil and gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a given well decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or gas it produces. We attempt to overcome this natural decline by developing existing properties, implementing secondary and tertiary recovery techniques and by acquiring more reserves than we produce. Our future growth may vary from year-to-year depending on our ability to enhance production levels from existing reserves and to continue to add reserves in excess of production through exploration, development and acquisition. We will maintain our focus on costs necessary to produce our reserves as well as the costs necessary to add reserves through production enhancement, drilling and acquisitions. Our ability to make capital expenditures to increase production from existing reserves and to acquire more reserves is dependent on availability of capital resources, and can be limited by many factors, including the ability to obtain capital in a cost-effective manner and to obtain permits and regulatory approvals in a timely manner.

Results of Operations

For the purposes of management's discussion and analysis of the results of operations, management has analyzed the operational results for the three and nine months ended September 30, 2013 and 2012, respectively.

The following table presents our sales volumes, revenues and operating expenses, and sets forth our sales prices, costs and expenses on a barrel of oil equivalent ("Boe") basis for the periods indicated.

                                                           Three Months Ended                                     Nine Months Ended
                                                              September 30,                                         September 30,
                                                      2013                        2012                      2013                        2012
                                                 (in thousands, except where indicated)                (in thousands, except where indicated)
Net Sales:
Total sales (MBoe)                                             1,058                     862                        3,298                    2,482
Average daily sales (Boe/d)                                   11,504                   9,365                       12,081                    9,058
Average Sales Prices ($/Boe):
Average sales price (excluding
derivative settlements)                      $                 84.17         $         73.58       $                77.95         $          77.12
Operating Expenses ($/Boe):
Lease operating                              $                 23.76         $         24.75       $                23.03         $          23.40
Production and ad valorem taxes                                 8.85                    9.77                         9.24                    11.40
General and administrative                                      8.37                    7.74                         8.05                     7.08
General and administrative (excluding
non-cash
compensation expense)                                           5.42                    4.77                         5.09                     4.52
Depletion, depreciation, amortization
and accretion                                                  25.20                   22.75                        24.36                    22.41

Quarter Ended September 30, 2013, Compared to the Quarter Ended September 30, 2012

Revenue. Revenue from oil and gas activities increased by 41% to $89.1 million during 2013, from $63.4 million during 2012. Of the $25.7 million increase in revenue, approximately $14.5 million was attributable to increased production and $11.2 million was attributable to increased commodity pricing. Average sales price for the quarter, excluding derivative settlements, increased from $73.58 per Boe in 2012 to $84.17 per Boe in 2013, primarily as a function of increased commodity pricing. Sales volumes increased 23% during 2013 as compared to 2012, from 862 MBoe to 1,058 MBoe. The majority of the production increase was related to the Permian Acquisitions.

Operating Expenses. Lease operating expenses include direct labor, contract services, field office rent, production and ad valorem taxes, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, workover expenses, utilities and other customary charges. Resolute assesses lease operating expenses in part by monitoring the expenses in relation to production volumes and the number of wells operated.

Lease operating expenses increased to $25.1 million during 2013, from $21.3 million during 2012. The $3.8 million, or 18%, increase was mainly attributable to additional operating expenses associated with the Permian Acquisitions and increased operational activity in the Permian Basin. On a per-unit basis, lease operating expense decreased by 4% from $24.75 to $23.76.

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Production and ad valorem taxes in 2013 of $9.4 million increased over 2012 production and ad valorem taxes of $8.4 million, but were less on a per-unit basis, mainly due to a decrease in ad valorem tax estimates in Utah and increased revenue derived from areas with lower tax rates. As a result, we expect to see an overall lower production tax rate going forward. Production and ad valorem taxes were 11% of total revenue in 2013 versus 13% of total revenue in 2012.

Depletion, depreciation, amortization and accretion expenses increased to $26.7 million during 2013, as compared to $19.6 million during 2012. The $7.1 million, or 36%, increase is principally due to higher production, a higher depletable base resulting in an increase in the depletion, depreciation and amortization rate from $22.75 per Boe in 2012 to $25.20 per Boe in 2013.

General and administrative expenses include the costs of employees and executive officers, related benefits, share-based compensation, office leases, professional fees, general corporate overhead and other costs not directly associated with field operations. Resolute monitors its general and administrative expenses carefully, attempting to balance the cash effect of incurring general and administrative costs against the related benefits with a focus on hiring and retaining highly qualified staff who can add value to the Company's asset base.

General and administrative expenses increased to $8.9 million during 2013, as compared to $6.7 million during 2012. The $2.2 million, or 33%, increase in general and administrative expenses mainly resulted from increases of $2.5 million in salaries and wages required to meet the demand of increasing operations across our primary focus areas, $0.6 million of increased share-based compensation, $0.3 million in professional services, offset by increased capitalized general and administrative costs and overhead billings. On a unit-of-production basis, general and administrative expenses increased 8%. Cash based general and administrative expense increased from $4.1 million to $5.7 million, or 40%.

Other Income (Expense). All of our oil and gas derivative instruments are accounted for under mark-to-market accounting rules, whereby the fair value of derivative contracts are reflected as either an asset or a liability on the balance sheet. The change in the fair value during an accounting period is recorded in the income statement for that period. During 2013, the loss on oil and gas commodity derivatives was $16.6 million, consisting of $21.9 million of derivative settlements, including $10.7 million paid to restructure or terminate certain 2013 derivative contracts. During 2012, the loss on oil and gas derivatives was $6.8 million, consisting of $3.3 million of derivative settlements.

Interest expense in 2013 increased to $6.8 million from the $4.6 million recorded in 2012 as a result of a higher average debt balance and a higher weighted average interest rate due to the follow-on issuance of our 8.50% Senior Notes (defined below). The components of our interest expense are as follows (in thousands).

                                                                  Three Months Ended
                                                                    September 30,
                                                                2013              2012
8.50% Senior notes                                            $   8,500         $  5,313
Credit facility                                                   1,964              476
Amortization of deferred financing costs and senior
notes premium                                                       632              333
Other                                                                 4                3
Capitalized interest                                             (4,337 )         (1,524 )

Total interest expense                                        $   6,763         $  4,601

Income Tax Benefit (Expense). Income tax benefit recognized during 2013 was $1.6 million, or 37.7% of the loss before income taxes, as compared to income tax benefit of $1.5 million, or 38.0% of the loss before income taxes in 2012.

Nine Months Ended September 30, 2013, compared to Nine Months Ended September 30, 2012

Revenue. Revenue from oil and gas activities increased by 34% to $257.1 million during 2013, from $191.4 million during 2012. Of the net $65.7 million increase in revenue, approximately $63.0 million was attributable to increased production and $2.7 million was attributable to increased commodity prices. Average sales price for the period, excluding derivative settlements, increased from $77.12 per Boe in 2012 to $77.95 per Boe in 2013, primarily as a function of increased commodity pricing. Sales volumes increased 33% during 2013 as compared to 2012, from 2,482 MBoe to 3,298 MBoe. The increase is mainly due to increased production from new wells in the Permian Basin Properties as a result of the Permian Acquisitions as well as drilling activities during 2013.

Operating Expenses. Aggregate lease operating expenses increased to $75.9 million during 2013, from $58.1 million during 2012. The $17.8 million, or 31%, increase was attributable to additional operating expenses associated with the Permian Acquisitions. On a per-unit basis, lease operating expense decreased 2% from $23.40 in 2012 to $23.03 in 2013.

Production and ad valorem taxes increased by 8% to $30.5 million in 2013 versus $28.3 million in 2012, due to the increase in production over 2012 offset by lower ad valorem tax estimates associated with the Company's Aneth Field Properties. Production and ad valorem taxes were 12% of total revenue in 2013 versus 15% of total revenue in 2012.

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Depletion, depreciation, amortization and accretion expenses increased to $80.4 million during 2013, as compared to $55.6 million during 2012. The $24.8 million, or 44%, increase is principally due to higher production, a higher depletable base and an increase in the depletion, depreciation and amortization rate from $22.41 per Boe in 2012 to $24.36 per Boe in 2013 as a result of increased finding costs on new drilling and completion activities.

General and administrative expenses for Resolute increased to $26.6 million during 2013, as compared to $17.6 million during 2012. The $9.0 million, or 51%, increase in general and administrative expenses resulted from increases of $7.6 million in salaries and wages, $3.4 million in share-based compensation expense, $1.2 million in professional services and $0.4 million in corporate overhead, offset by increases in capitalized labor and overhead billings. On a unit-of-production basis, general and administrative expenses increased 14%. Cash based general and administrative expense increased from $11.2 million to $16.8 million, or 50%.

Other Income (Expense). During 2013, the loss on oil and gas derivatives was $16.5 million, consisting of $35.6 million of derivative settlements, including $10.7 million paid to restructure or terminate certain 2013 derivative contracts. During 2012, the gain on oil and gas derivatives was $8.9 million, consisting of $21.0 million of derivative settlements.

Interest expense in 2013 increased to $22.0 million from the $9.5 million recorded in 2012 as a result of the higher interest rate associated with the Senior Notes issuances in 2012 and increased average borrowings. The components of our interest expense are as follows (in thousands).

                                                                  Nine Months Ended
                                                                    September 30,
                                                                2013              2012
8.50% Senior notes                                            $  25,500         $  9,208
Credit facility                                                   6,342            2,599
Amortization of deferred financing costs and senior
notes premium                                                     1,877            1,037
Other                                                                (8 )              3
Capitalized interest                                            (11,686 )         (3,336 )

Total interest expense                                        $  22,025         $  9,511

Income Tax Benefit (Expense). Income tax expense recognized during 2013 was $2.0 million, or 37.2% of income before income taxes, as compared to income tax expense of $11.7 million, or 37.3% of the income before income taxes during 2012.

Liquidity and Capital Resources

Our primary sources of liquidity have been cash generated from operations, amounts available under our Credit Facility (defined below), proceeds from warrant exercises, issuance of Senior Notes (defined below), public equity offerings and sales of non-strategic oil and gas properties. For purposes of Management's Discussion and Analysis of Liquidity and Capital Resources, we have analyzed our cash flows and capital resources for the nine months ended September 30, 2013 and 2012.

                                                     Nine Months Ended
                                                       September 30,
                                                    2013            2012
                                                       (in thousands)
         Cash provided by operating activities   $  110,908      $   67,580
         Cash used in investing activities         (333,529 )      (145,411 )
         Cash provided by financing activities      222,624          79,128

Net cash provided by operating activities was $110.9 million for the first nine months of 2013 compared to $67.6 million for the 2012 period, which reflects the increased production, commodity pricing and working capital fluctuations in 2013.

We plan to reinvest a sufficient amount of our cash flow in our development operations in order to maintain our production over the long term, and plan to use external financing sources as well as cash flow from operations and cash reserves to increase our production.

Net cash used in investing activities was $333.5 million in 2013 compared to $145.4 million in 2012. The primary investing activity in 2013 was cash used for capital expenditures of $451.0 million. Capital expenditures consisted of $258 million paid to acquire additional interests in the Permian Properties, $32.6 million in compression and facility and drilling projects in Aneth Field, $14.9 million in CO2 acquisition, $111.2 million in drilling activities and infrastructure projects in the Permian Basin of West Texas, $32.5 million in . . .

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