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REN > SEC Filings for REN > Form 10-Q on 11-Aug-2014All Recent SEC Filings

Show all filings for RESOLUTE ENERGY CORP

Form 10-Q for RESOLUTE ENERGY CORP


11-Aug-2014

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, 2013, 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 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 Big Horn and Powder River 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, 2013, our estimated net proved reserves were approximately 59.4 million equivalent barrels of oil ("MMBoe"), of which approximately 79% and 57% were proved developed reserves and proved developed producing reserves, respectively. Approximately 80% of our net proved reserves were oil and approximately 88% were oil and natural gas liquids ("NGL"). The December 31, 2013, pre-tax present value discounted at 10% of our net proved reserves was $1,054 million and the standardized measure of our estimated net proved reserves was $893 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, operating cash flow and Adjusted EBITDA. 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, 2013.

Aneth Field Properties

Our largest asset, constituting 59% of our net proved reserves as of December 31, 2013, 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 June 30, 2014. 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.

The field is connected by pipeline to a refinery located near Gallup, New Mexico that is owned and operated by Western Refining Southwest, Inc., a subsidiary of Western Refining Inc ("Western"). Western currently purchases all of the oil production from Aneth Field, and in July 2014, we entered into a new oil sales contract that provides for Resolute to retain a price equal to the NYMEX oil price minus a differential of $9.50 per barrel of oil, which represents a premium to market. The contract is scheduled for termination on December 31, 2014. Resolute is currently in negotiations with Western and expects to enter into a new contract covering 2015 through 2016 before the expiration of the existing contract. If, for any reason, Western is unable to process our oil, there is alternative access to markets through rail and truck facilities or, in early 2015, through the Texas-New Mexico pipeline.

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Permian Properties

Our Permian Properties, constituting 33% of net proved reserves as of December 31, 2013, are located in the Permian Basin of west Texas and southeast New Mexico, and are divided between three principal project areas. Our 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 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 our Midland and Delaware basin 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 these areas will be increasingly focused on horizontal drilling activity targeting these same formations.

During the second quarter of 2014, we completed 4 gross (2.5 net) wells on our Permian Properties, including 3 gross (1.5 net) non-operated vertical wells in the Midland Basin. We were in the process of drilling 1 gross (0.8 net) well and had 2 gross (1.6 net) wells awaiting completion operations at quarter end. All of the operated wells completed, in the process of drilling and awaiting completion are located in the Delaware Basin.

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 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 to be exercised. On March 22, 2013, we exercised our option and acquired the remaining 67.65% interest in the RSP properties. The purchase price for the acquired properties, which we refer to as our Gardendale area, 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 and 80 producing wells and facilities for gathering, water sourcing and water disposal. The acreage is largely held by production. We believe that growth potential exists from approximately 23 gross prospective horizontal locations with multiple targets in the Wolfcamp, Spraberry and Atoka formations, along with potentially 85 recompletion opportunities across the entire acreage position in the Midland Basin.

Wyoming Properties

Hilight Field, constituting 8% of net proved reserves as of December 31, 2013, 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, Niobrara, Shannon, Sussex, Parkman 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. In the fourth quarter of 2013, we successfully completed a horizontal well in the Turner formation. Based on this success, we drilled two additional appraisal wells in the Turner formation in the second quarter of 2014 which we expect to complete during the third quarter of 2014. We believe there may be as many as 45 drilling locations in the Turner inside our existing leasehold. During the drilling of our recent wells, we collected additional petrophysical data in the Parkman, Shannon, Sussex and Niobrara formations.

At quarter end, we were in the process of drilling 1 gross (0.9 net) well and had 1 gross (1.0 net) well awaiting completion operations.

Divestiture of North Dakota Properties

During 2013 we divested all of our non-operated properties located in the Bakken trend of North Dakota through three separate transactions for net proceeds of approximately $70.1 million. During March 2014 we divested our remaining operated properties in North Dakota for approximately $4.8 million.

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 and lower realized prices for our 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.

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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 will depend 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 properties 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 six months ended June 30, 2014, in comparison to results for the three and six months ended June 30, 2013.

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            Six Months Ended
                                                        June 30,                     June 30,
                                                   2014           2013          2014          2013
Net Sales:
Total sales (MBoe)                                   1,120         1,193         2,254         2,240
Average daily sales (Boe/d)                         12,311        13,107        12,454        12,374
Average Sales Prices ($/Boe):
Average sales price (excluding commodity
derivative settlements)                         $    78.96      $  74.72      $  79.56      $  75.02
Operating Expenses ($/Boe):
Lease operating                                 $    26.23      $  21.45      $  25.75      $  22.68
Production and ad valorem taxes                       8.94          9.12          9.14          9.42
General and administrative                            9.37          7.65          8.49          7.90
General and administrative (excluding
non-cash
compensation expense)                                 5.61          4.08          5.42          4.93
Depletion, depreciation, amortization and
accretion                                            28.23         24.14         28.19         23.97

Quarter Ended June 30, 2014, Compared to the Quarter Ended June 30, 2013

Revenue. Revenue from oil and gas activities decreased by 1% to $88.5 million during 2014, from $89.1 million during 2013. Of the $0.6 million decrease in revenue, approximately $5.4 million was attributable to decreased production, offset by $4.8 million in increased commodity pricing. Average sales price for the quarter, excluding derivative settlements, increased from $74.72 per Boe in 2013 to $78.96 per Boe in 2014, primarily as a function of increased commodity pricing. Sales volumes decreased 6% during 2014 as compared to 2013, from 1,193 MBoe to 1,120 MBoe. The majority of the production decrease was due to the disposition of the North Dakota Properties, which closed on July 15, 2013.

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 $29.4 million during 2014, from $25.6 million during 2013. The $3.8 million, or 15%, increase was attributable to additional operating expenses associated with increased operational activity in the Permian Basin. Costs in most operating areas have been as anticipated during the quarter but operating costs in certain areas of the Permian Basin have exceeded our expectations. The Company has implemented cost reduction initiatives in the Permian Basin that we anticipate will lower per barrel operating costs in the future, although when such savings will be realized cannot be predicted with accuracy. On a per-unit basis, lease operating expense increased 22% from $21.45 in 2013 to $26.23 in 2014.

Production and ad valorem taxes in 2014 of $10.0 million decreased from $10.9 million in 2013 and were less on a per-unit basis, due to decreased ad valorem tax estimates and comparatively greater revenues generated in areas with lower tax rates. Production and ad valorem taxes were 11.3% of total revenue in 2014 versus 12.2% of total revenue in 2013.

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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. We monitor our 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 our asset base.

General and administrative expenses increased to $10.5 million during 2014, as compared to $9.1 million during 2013. The $1.4 million, or 15%, increase in general and administrative expenses primarily resulted from increases of $1.2 million in personnel expenses, $0.2 million in professional services, $0.1 million in corporate overhead, offset by increases in capitalized labor and overhead billings. Cash-based general and administrative expense increased from $4.9 million to $6.3 million, or 29%.

Depletion, depreciation, amortization and accretion expenses increased to $31.6 million during 2014, as compared to $28.8 million during 2013. The $2.8 million, or 10%, increase is principally due to an increase in the depletion, depreciation and amortization rate as a result of the decrease in proved undeveloped reserves at year end 2013 due to the application of the SEC five-year rule for development of proved undeveloped properties. On a per-unit basis, depreciation, amortization and accretion expenses increased from $24.14 per Boe in 2013 to $28.23 per Boe in 2014.

Other Income (Expense). All of our oil and gas derivative instruments are accounted for under mark-to-market accounting rules, which provide for the fair value of the contracts to be reflected as either an asset or a liability on the balance sheet. The change in the fair value during an accounting period is reflected in the income statement for that period. During 2014, the loss on oil and gas commodity derivatives was $22.2 million, consisting of $7.3 million of derivative settlement losses and $14.9 million of mark-to-market losses. During 2013, the gain on oil and gas commodity derivatives was $6.8 million, consisting of $6.9 million of derivative settlement losses and $13.7 million of mark-to-market gains.

Interest expense in 2014 increased to $7.6 million from the $7.2 million recorded in 2013. The $0.4 million increase in interest expense was primarily due to $0.7 million of decreased capitalized interest, offset by $0.3 million in decreased interest expense due to decreased levels of borrowings and other. The components of our interest expense are as follows (in thousands):

                                                                   Three Months Ended
                                                                        June 30,
                                                                 2014              2013
8.50% senior notes                                             $   8,500         $  8,500
Credit facility                                                    2,412            2,729
Amortization of deferred financing costs and senior notes
premium                                                              589              642
Other, net                                                            36               (9 )
Capitalized interest                                              (3,960 )         (4,681 )

Total interest expense                                         $   7,577         $  7,181

Income Tax Benefit (Expense). Income tax benefit recognized during 2014 was $6.7 million, or 29.3% of the loss before income taxes, as compared to income tax expense of $5.4 million, or 37.3% of the income before income taxes in 2013. The lower 2014 benefit rate was attributable to noncash executive compensation that is anticipated to be nondeductible for income tax purposes and to permanent differences related to share-based compensation.

Six Months Ended June 30, 2014, compared to Six Months Ended June 30, 2013

Revenue. Revenue from oil and gas activities increased by 7% to $179.3 million during 2014, from $168.0 million during 2013. Of the net $11.3 million increase in revenue, approximately $1.1 million was attributable to increased production and $10.2 million of increased commodity pricing. Average sales price for the period, excluding derivative settlements, increased from $75.02 per Boe in 2013 to $79.56 per Boe in 2014, primarily as a function of increased commodity pricing. Sales volumes increased during 2014 as compared to 2013, from 2,240 MBoe to 2,254 MBoe. The increase is primarily due to increased production from the drilling of additional wells in both the Permian as well as the Wyoming Properties, offset by the disposition of the North Dakota Properties, which closed on July 15, 2013.

Operating Expenses. Aggregate lease operating expenses increased to $58.0 million during 2014, from $50.8 million during 2013. The $7.2 million, or 14%, increase was attributable to additional operating expenses associated with the Permian Acquisitions and increased operational activity in the Permian Basin. Costs in most operating areas have been as anticipated during the first six months of 2014 but operating costs in certain areas of the Permian Basin have exceeded our expectations. The Company has implemented cost reduction initiatives in the Permian Basin that we anticipate will lower per barrel operating costs in the future, although when such savings will be realized cannot be predicted with accuracy. On a per-unit basis, lease operating expense increased 14% from $22.68 in 2013 to $25.75 in 2014.

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Production and ad valorem taxes decreased to $20.6 million in 2014, versus $21.1 million in 2013, due to decreased ad valorem tax estimates and comparatively greater revenues generated in areas with lower tax rates. Production and ad valorem taxes were 11.5% of total revenue in 2014 versus 12.6% of total revenue in 2013.

Depletion, depreciation, amortization and accretion expenses increased to $63.5 million during 2014, as compared to $53.7 million during 2013. The $9.8 million, or 18%, increase is principally due to an increase in the depletion, depreciation and amortization rate from $23.97 per Boe in 2013 to $28.19 per Boe in 2014 as a result of the decrease in proved undeveloped reserves at year end 2013 due to the application of the SEC five-year rule for development of proved undeveloped properties.

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 for Resolute increased to $19.1 million during 2014, as compared to $17.7 million during 2013. The $1.4 million, or 8%, increase in general and administrative expenses resulted from increases of $0.8 million in personnel expenses, $0.3 million in share-based compensation expense, $0.3 million in corporate overhead, $0.2 million in professional services, offset by increases in capitalized labor and overhead billings. On a unit-of-production basis, general and administrative expenses increased 7%. Cash based general and administrative expense increased from $11.0 million to $12.2 million, or 11%.

Other Income (Expense). During 2014, the loss on oil and gas commodity derivatives was $30.1 million, consisting of $12.1 million of derivative settlement losses and $18.0 million of mark-to-market losses. During 2013, the gain on oil and gas commodity derivatives was $0.1 million, consisting of $13.8 million of mark-to-market gains and $13.7 million of derivative settlement losses.

Interest expense in 2014 increased to $15.4 million from the $15.3 million recorded in 2013 as a result of an increase of $0.7 million in interest expense due to increased levels of borrowing, offset by $0.6 million of increased capitalized interest and other. The components of our interest expense were as follows (in thousands).

                                                             Six Months Ended June 30,
                                                             2014                 2013
8.50% senior notes                                       $     17,000         $     17,000
Credit facility                                                 5,120                4,378
Amortization of deferred financing costs and senior
notes premium                                                   1,188                1,245
Other                                                            (185 )                (12 )
Capitalized interest                                           (7,750 )             (7,349 )

                                                         $     15,373         $     15,262

Income Tax Benefit (Expense). Income tax benefit recognized during 2014 was $7.8 million, or 28.4% of the loss before income taxes, as compared to income tax expense of $3.6 million, or 37.4% of the income before income taxes during 2013. The lower 2014 benefit rate was attributable to noncash executive compensation that is anticipated to be nondeductible for income tax purposes and to permanent differences related to share-based compensation.

Liquidity and Capital Resources

Our primary sources of liquidity have been cash generated from operations, amounts available under our Credit Facility, proceeds from the issuance of debt and equity securities and sales of 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 six months ended June 30, 2014 and 2013.

                                                           Six Months Ended
                                                               June 30,
                                                         2014            2013
                                                            (in thousands)
     Cash provided by operating activities             $  91,732      $   64,524
     Cash used in investing activities                   (88,970 )      (322,163 )
     Cash provided by (used in) financing activities      (1,546 )       257,584

Net cash provided by operating activities was $91.7 million for the first six months of 2014 compared to $64.5 million for the 2013 period. The increase in net cash provided by operating activities in 2014 over 2013 was primarily due to changes in operating assets and liabilities.

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We plan to reinvest a sufficient amount of our cash flow into 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 $89.0 million in 2014 compared to $322.2 million in 2013. The primary investing activity in 2014 was cash used for . . .

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