NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Organization and Description of the Business
RSP Permian, Inc., a Delaware corporation ("RSP Inc.," the "Company," "we," "our," or "us"), is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of the Company’s acreage is located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin, both sub-basins of the Permian Basin. The Midland Basin properties are primarily in the adjacent counties of Midland, Martin, Andrews, Ector and Glasscock. The Delaware Basin properties are in Loving and Winkler counties. The Company’s common stock is listed and traded on the NYSE under the ticker symbol “RSPP.”
Proposed Merger with Concho Resources Inc.
On March 27, 2018, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Concho Resources Inc., a Delaware corporation (“Concho”), and Green Merger Sub Inc., a Delaware corporation and wholly owned subsidiary of Concho (“Merger Sub”), pursuant to which Merger Sub will merge with and into RSP Inc. (the "Merger"), with RSP Inc. surviving the Merger as a wholly owned subsidiary of Concho. Concho's common stock is listed and traded on the NYSE under the ticker symbol "CXO." The closing of the Merger is expected to occur in the third quarter of 2018.
On the terms and subject to the conditions set forth in the Merger Agreement, upon consummation of the Merger, each share of RSP Inc. common stock, par value
$0.01
per share, issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive from Concho
0.320
of a fully-paid and nonassessable share of common stock, par value
$0.001
per share, of Concho (“Concho Shares”).
The completion of the Merger is subject to certain customary mutual conditions, including (i) the receipt of the required approvals from the stockholders of RSP Inc. and Concho, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, (iii) the absence of any governmental order or law that makes consummation of the Merger illegal or otherwise prohibited, (iv) Concho’s registration statement on Form S-4 having been declared effective by the SEC under the Securities Act of 1933, (v) Concho Shares issuable in connection with the Merger having been authorized for listing on the NYSE, upon official notice of issuance, and (vi) the receipt by each party of a customary opinion that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the U.S. tax code. The obligation of each party to consummate the Merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions) and the other party having performed in all material respects its obligations under the Merger Agreement.
The Merger Agreement contains termination rights for each of Concho and RSP Inc., including, among others, if the consummation of the Merger does not occur on or before October 31, 2018. Upon termination of the Merger Agreement under specified circumstances, including the termination by RSP Inc. in the event of a change of recommendation by Concho's board of directors, Concho would be required to pay RSP Inc. a termination fee of
$350.0 million
. Upon termination of the Merger Agreement under specified circumstances, including, generally, the termination by Concho in the event of a change of recommendation by the RSP Inc.'s board of directors or by RSP Inc. to enter into an alternative acquisition agreement, RSP Inc. would be required to pay Concho a termination fee of
$250.0 million
.
On April 20, 2018, Concho filed a registration statement on Form S-4 (the “Form S-4”) to register the Concho Shares to be issued in the Merger. The Form S-4 is subject to review by the SEC, and Concho will file one or more amendments to the Form S-4 in the future.
Additional information on the proposed Merger is included in the Form 8-K filed with the SEC on March 28, 2018.
Basis of Presentation
These consolidated financial statements have been prepared by the Company pursuant to the rules and regulations of the SEC and are presented in accordance with generally accepted accounting principles in the United States (“GAAP”). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation. The consolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in
the United States have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. The financial statements in this Quarterly Report on Form 10–Q should be read together with the financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended
December 31, 2017
, which contains a complete summary of the Company’s significant accounting policies and disclosures.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. The more significant estimates pertain to proved oil, natural gas liquids ("NGLs") and natural gas reserves, asset retirement obligations (“AROs”), equity-based compensation, estimates relating to oil, NGLs and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively.
Significant assumptions are required in the valuation of proved oil, NGLs and natural gas reserves that may affect the amount at which oil and natural gas properties are recorded. Depletion of oil and natural gas properties are determined using estimates of proved oil, NGLs and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price estimates. It is possible that these estimates could be revised at future dates and such revisions could be material.
Reclassifications
Certain reclassifications have been made to prior periods to conform to current period presentation. None of these reclassifications impacted previously reported stockholders' equity, cash flows, or operating income.
Revenue from Contracts with Customers (Topic 606) - ASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) ("ASC 606"). ASC 606 provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific guidance and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. We adopted ASC 606 in the first quarter of 2018 using the modified retrospective method. The adoption of ASC 606 did not result in a cumulative effect adjustment on our opening accumulated earnings balance in our consolidated balance sheet. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historical accounting under ASC 605, Revenue Recognition ("ASC 605").
Disaggregation of revenue
In accordance with ASC 606, the Company disaggregates revenues from contracts with customers by product type. All of the Company's revenue is recognized at a point in time when the customer obtains control of the delivered product, which for the Company is primarily at the wellhead. The following table presents our revenues disaggregated by product type and the impact of applying ASC 606 on our current period results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2018
|
(in thousands)
|
|
As reported (ASC 606)
|
|
Historical (ASC 605)
|
|
Effect of change
|
REVENUES
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
251,977
|
|
|
$
|
251,977
|
|
|
$
|
—
|
|
Natural gas sales
|
|
8,432
|
|
|
9,601
|
|
|
(1,169
|
)
|
NGLs sales
|
|
15,913
|
|
|
18,074
|
|
|
(2,161
|
)
|
Total revenues
|
|
276,322
|
|
|
279,652
|
|
|
(3,330
|
)
|
OPERATING EXPENSES
|
|
|
|
|
|
|
Lease operating expenses
|
|
32,135
|
|
|
35,465
|
|
|
(3,330
|
)
|
OPERATING INCOME
|
|
130,062
|
|
|
130,062
|
|
|
—
|
|
NET INCOME
|
|
$
|
89,573
|
|
|
$
|
89,573
|
|
|
$
|
—
|
|
Changes to revenues and lease operating expenses shown in the table above are due to the conclusion under ASC 606 that the Company meets the definition of an agent for certain of its gas processing and purchase contracts, thus the fees paid to these service providers are recorded as a deduction to revenues. In contracts where the Company meets the definition of a principal under the control model defined in ASC 606, the fees paid to these service providers are recorded as lease operating expenses.
Oil, natural gas and NGLs sales
We generally sell oil production at the wellhead for a contractually specified index price plus or minus a differential, less transportation costs, and recognize revenue at the net price received.
Under our gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. For those contracts where we have concluded we are the agent and the midstream processing entity is our customer, we recognize natural gas and NGLs revenues based on the net amount of the proceeds received from the midstream processing entity. Alternatively, for those contracts where we have concluded we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with transportation, gathering, processing and compression fees presented as a component of lease operating expenses in our consolidated statements of operations.
We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGLs sales are typically not received for 30 to 90 days after the date production is delivered. At the end of each month, we estimate the amount of production that was delivered to the purchaser and the price that will be received. Variances between our estimates and the actual amounts received, if any, are recorded in the month payment is received. During the first quarter of 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods were not significant.
Practical expedients and exemptions
We do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which the variable consideration is allocated entirely to a wholly unsatisfied performance obligation, as allowed under ASC 606. Under our sales contracts, each barrel of oil and NGLs, or Mmbtu of natural gas represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Accounts Receivable
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
As of March 31, 2018
|
|
As of December 31, 2017
|
Sale of oil, natural gas and NGLs
|
|
$
|
110,722
|
|
|
$
|
95,942
|
|
Joint interest owners
|
|
17,141
|
|
|
14,880
|
|
Federal income tax receivable
|
|
335
|
|
|
335
|
|
Total accounts receivable
|
|
$
|
128,198
|
|
|
$
|
111,157
|
|
Accounts receivable, which are primarily from the sale of oil, NGLs and natural gas, are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. In addition, settled but uncollected derivative contracts, receivables related to joint interest billings and income tax receivables are included in accounts receivable. The Company routinely reviews outstanding balances, assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. The need for an allowance is determined based upon reviews of individual accounts, historical losses, existing economic conditions and other pertinent factors. Bad debt expense was
zero
for the three
months ended
March 31, 2018
and
2017
, respectively.
Oil and Natural Gas Properties
The Company uses the successful efforts method of accounting for its oil and natural gas exploration and production activities. Costs incurred by the Company related to the acquisition of oil and natural gas properties and the cost of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when determined to be unsuccessful.
The Company may capitalize interest on expenditures for significant exploration and development projects that last more than
six months
, while activities are in progress to bring the assets to their intended use. The Company has not capitalized any interest as projects generally lasted less than
six months
. Costs incurred to maintain wells and related equipment, lease and well operating costs and other exploration costs are expensed as incurred.
Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted using the unit-of-production method based on proved reserves. Capitalized exploration well costs and development costs, including AROs, are depleted using the unit-of-production method based on proved developed reserves. For the
three months ended March 31, 2018
and
2017
, depletion expense for oil and natural gas producing property was
$75.4 million
and
$60.4 million
, respectively. Depletion expense is included in depreciation, depletion and amortization in the accompanying consolidated statements of operations.
The Company’s oil and natural gas properties as of
March 31, 2018
and
December 31, 2017
consisted of the following:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
March 31, 2018
|
|
December 31, 2017
|
Proved oil and natural gas properties
|
|
$
|
4,189,377
|
|
|
$
|
3,936,565
|
|
Unproved oil and natural gas properties
|
|
2,859,631
|
|
|
2,865,952
|
|
Total oil and natural gas properties
|
|
7,049,008
|
|
|
6,802,517
|
|
Less: Accumulated depletion
|
|
(853,720
|
)
|
|
(778,596
|
)
|
Total oil and natural gas properties, net
|
|
$
|
6,195,288
|
|
|
$
|
6,023,921
|
|
In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of
March 31, 2018
and
December 31, 2017
, there were
no
costs capitalized in connection with exploratory wells in progress.
Proved oil and natural gas properties are evaluated for impairment annually or whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows available which is the level at which depletion is calculated. To determine if an asset is impaired, the Company compares the carrying value of the asset to the undiscounted future net cash flows by applying estimates of future oil, NGLs and natural gas prices to the estimated future production of oil, NGLs and natural gas reserves over the economic life of the asset and deducting future costs. Future net cash flows are based upon our reservoir engineers’ estimates of proved reserves and risk-adjusted probable reserves.
For a property determined to be impaired, an impairment loss equal to the difference between the asset’s carrying value and its estimated fair value is recognized. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value.
No
impairment of proved property was recorded for the
three months ended March 31, 2018
or
2017
. The calculation of expected future net cash flows in impairment evaluations are primarily based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserve quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted probable reserves. The
Company’s estimates for future oil and natural gas prices used in the impairment evaluations are based on observable prices for the next three years, and then held constant for the remaining lives of the properties.
Unproved property costs and related leasehold expirations are assessed quarterly for potential impairment and when industry conditions dictate an impairment may be possible. For the
three months ended March 31, 2018
and
2017
, we impaired approximately
$4.2 million
and
$0.1 million
, respectively, of unproved oil and natural gas properties, which primarily related to management’s expectation that certain leasehold interests would expire and not be renewed.
Proceeds from the sales of individual oil and natural gas properties that are part of a depletion base are credited to accumulated depletion with no immediate impact on income until the entire depletion base is sold. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Gains and losses arising from the sale of properties are generally included in operating income.
Accrued Expenses
Accrued expenses consist of the following:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
March 31, 2018
|
|
December 31, 2017
|
Accrued capital expenditures
|
|
$
|
91,372
|
|
|
$
|
82,748
|
|
Other accrued expenses
|
|
25,000
|
|
|
36,691
|
|
Accrued expenses
|
|
$
|
116,372
|
|
|
$
|
119,439
|
|
Asset Retirement Obligation
The Company records AROs related to the retirement of long-lived assets at the time a legal obligation is incurred and the liability can be reasonably estimated. AROs are recorded as long-term liabilities with a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.
The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future down-hole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of the surface acreage to a condition similar to that existing before oil and natural gas extraction began.
In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
After recording these amounts, the ARO liability is accreted to its future estimated value using the same assumed credit adjusted rate and the associated capitalized costs are depreciated on a unit-of-production basis.
The following is a reconciliation of our ARO liability for the three months ended March 31, 2018:
|
|
|
|
|
|
(in thousands)
|
|
|
Asset retirement obligation at beginning of period
|
|
$
|
15,849
|
|
Liabilities incurred
|
|
789
|
|
Liabilities settled
|
|
(278
|
)
|
Accretion expense
|
|
205
|
|
Asset retirement obligation at end of period
|
|
$
|
16,565
|
|
Income Taxes
The following is an analysis of the Company’s consolidated income tax expense for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
(in thousands)
|
|
2018
|
|
2017
|
Current
|
|
$
|
—
|
|
|
$
|
1,498
|
|
Deferred
|
|
21,932
|
|
|
13,574
|
|
Income Tax Expense
|
|
$
|
21,932
|
|
|
$
|
15,072
|
|
Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement carrying amounts and tax basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. We have not recognized any interest and penalties relating to unrecognized tax benefits in our consolidated financial statements.
New Accounting Pronouncements
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). ASU 2016-02 generally requires all lease transactions (with expected lease terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. We do not plan to early adopt the standard. We are currently evaluating the impact of ASU 2016-02 on our consolidated financial statements.
NOTE 3—ACQUISITIONS OF OIL AND NATURAL GAS PROPERTY INTERESTS
During the first quarter of 2018, we closed on bolt-on acquisitions of undeveloped acreage in the Delaware Basin for an aggregate total purchase price of
$8.7 million
.
NOTE 4—DERIVATIVE INSTRUMENTS
Commodity Derivative Instruments
The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its crude oil and natural gas production. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings.
Our commodity derivatives are comprised of the following instruments:
Collars
: Each collar transaction has an established price floor and ceiling, and certain collar transactions also include a short put. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is below the short put price, the Company receives from its counterparty an amount equal to the difference of the price floor and the short put price multiplied by the hedged contract volume.
Swaps
: Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
The following table summarizes all commodity derivative positions as of
March 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts expiring in the period ending:
|
|
|
June 30, 2018
|
|
September 30, 2018
|
|
December 31, 2018
|
|
2019
|
Oil Three-Way Collars:
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
1,941,000
|
|
|
1,319,000
|
|
|
1,227,000
|
|
|
—
|
|
Weighted average ceiling price ($/Bbl)(1)
|
|
$
|
59.07
|
|
|
$
|
60.56
|
|
|
$
|
60.96
|
|
|
$
|
—
|
|
Weighted average floor price ($/Bbl)(1)
|
|
$
|
47.11
|
|
|
$
|
47.79
|
|
|
$
|
48.00
|
|
|
$
|
—
|
|
Weighted average short put price ($/Bbl)(1)
|
|
$
|
37.11
|
|
|
$
|
37.79
|
|
|
$
|
38.00
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
Oil Costless Collars:
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
516,000
|
|
|
1,212,000
|
|
|
1,058,000
|
|
|
2,555,000
|
|
Weighted average ceiling price ($/Bbl)(1)
|
|
$
|
60.20
|
|
|
$
|
60.10
|
|
|
$
|
60.11
|
|
|
$
|
58.04
|
|
Weighted average floor price ($/Bbl)(1)
|
|
$
|
45.00
|
|
|
$
|
46.33
|
|
|
$
|
46.52
|
|
|
$
|
52.50
|
|
|
|
|
|
|
|
|
|
|
Oil Swaps:
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
698,000
|
|
|
322,000
|
|
|
322,000
|
|
|
2,555,000
|
|
Weighted average swap price ($/Bbl)(1)
|
|
$
|
62.97
|
|
|
$
|
55.77
|
|
|
$
|
55.77
|
|
|
$
|
55.74
|
|
|
|
|
|
|
|
|
|
|
Mid-Cush Differential (Basis) Swaps:
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
2,730,000
|
|
|
2,760,000
|
|
|
2,760,000
|
|
|
2,555,000
|
|
Weighted average swap price ($/Bbl)(2)
|
|
$
|
(0.42
|
)
|
|
$
|
(0.42
|
)
|
|
$
|
(0.42
|
)
|
|
$
|
(0.29
|
)
|
(1)
The oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of West Texas Intermediate Light Sweet Crude.
(2) The Mid-Cush swap contracts are settled based on the difference in the arithmetic average during the calculation period of WTI MIDLAND ARGUS and WTI ARGUS prices in the Argus Americas Crude publication for the relevant period.
Derivative Fair Values and Gains
The following table presents the fair value of our derivative instruments. Our derivatives are presented as separate line items in our consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities based on the expected settlement dates of the instruments. The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. However, the fair value amounts are presented on a gross basis in our consolidated balance sheets and do not reflect the netting of asset and liability positions permitted under the terms of the Company’s master netting arrangements. See Note 5 for further discussion related to the fair value of the Company’s derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
Liabilities
|
(in thousands)
|
|
March 31, 2018
|
|
December 31, 2017
|
|
March 31, 2018
|
|
December 31, 2017
|
Derivative Instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current amounts
|
|
$
|
30,186
|
|
|
$
|
64
|
|
|
$
|
51,001
|
|
|
$
|
36,566
|
|
Noncurrent amounts
|
|
4,574
|
|
|
37
|
|
|
9,321
|
|
|
5,722
|
|
Total derivative instruments
|
|
$
|
34,760
|
|
|
$
|
101
|
|
|
$
|
60,322
|
|
|
$
|
42,288
|
|
Gains and losses on derivatives are reported in the consolidated statements of operations.
The following represents the Company’s reported gains on derivative instruments for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
(in thousands)
|
|
2018
|
|
2017
|
Net gain on derivative instruments
|
|
$
|
2,907
|
|
|
$
|
17,121
|
|
Credit-Risk Related Contingent Features in Derivatives
None of the Company’s derivative instruments contain credit-risk related contingent features.
No
amounts of collateral were posted by the Company related to net positions as of
March 31, 2018
and
December 31, 2017
.
NOTE 5—FAIR VALUE MEASUREMENTS
We value our derivatives and other financial instruments according to FASB ASC 820,
Fair Value Measurements and Disclosures
, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (“exit price”) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.
The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
•
Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
•
Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
•
Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data and may reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Reclassifications of fair value among Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers among Level 1, Level 2 or Level 3 during the
three months ended March 31, 2018
.
Fair Value Measurement on a Recurring Basis
Fair value of commodity derivative instruments
The fair value of derivative financial instruments is determined utilizing industry standard models incorporating assumptions and inputs, most of which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.
The following table presents a summary of the estimated net fair value of our commodity derivative instruments as of
March 31, 2018
and
December 31, 2017
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total fair value
|
As of March 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
(25,562
|
)
|
|
$
|
—
|
|
|
$
|
(25,562
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total fair value
|
As of December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
(42,187
|
)
|
|
$
|
—
|
|
|
$
|
(42,187
|
)
|
Fair value of other financial instruments
Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued expenses. The carrying amount of these instruments approximates fair value because of their short-term nature. The carrying value of our borrowings under our revolving credit facility ("Revolving Credit Facility") approximate fair value as these are subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair values of our senior notes are presented below. The estimated fair value of our
5.25%
senior unsecured notes due January 15, 2025 (“2025 Senior Notes”) and
6.625%
senior unsecured notes due October 1, 2022 (“2022 Senior Notes”) have been calculated based on quoted prices in active markets and are classified as Level 1.
The following table presents a summary of the estimated fair value of our senior notes as of March 31, 2018 and December 31, 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total fair value
|
2025 Senior Notes
|
|
$
|
466,340
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
466,340
|
|
2022 Senior Notes
|
|
732,963
|
|
|
—
|
|
|
—
|
|
|
732,963
|
|
|
|
December 31, 2017
|
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total fair value
|
2025 Senior Notes
|
|
$
|
464,022
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
464,022
|
|
2022 Senior Notes
|
|
734,706
|
|
|
—
|
|
|
—
|
|
|
734,706
|
|
Nonfinancial Assets and Liabilities
Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs. Our estimated abandonment costs are obtained primarily from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition or costs incurred historically for similar work. Additions to the Company’s AROs represent a nonrecurring Level 3 measurement.
The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.
NOTE 6—LONG-TERM DEBT
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
March 31, 2018
|
|
December 31, 2017
|
Revolving Credit Facility
|
|
$
|
445,000
|
|
|
$
|
375,000
|
|
5.25% Senior Notes due 2025
|
|
450,000
|
|
|
450,000
|
|
6.625% Senior Notes due 2022
|
|
700,000
|
|
|
700,000
|
|
Less: Discount
|
|
(900
|
)
|
|
(950
|
)
|
Less: Debt issuance costs
|
|
(14,349
|
)
|
|
(14,922
|
)
|
Total long-term debt
|
|
$
|
1,579,751
|
|
|
$
|
1,509,128
|
|
Revolving Credit Facility
As of
March 31, 2018
, the borrowing base under our amended and restated credit agreement was
$1.5 billion
, with a Company-elected commitment of
$900.0 million
, and lender commitments of
$2.5 billion
. The maturity date of the Revolving Credit Facility is December 19, 2021. The borrowing base under the Revolving Credit Facility remains subject to semi-annual review and redetermination by the lenders pursuant to the term of the credit agreement. The redetermination of the borrowing base occurs in May and November of each year and, among other things, depends on the volumes of proved oil, NGLs and natural gas reserves and an estimate of associated cash flows, and commodity hedge positions. As of
March 31, 2018
, we had
$445.0 million
in borrowings,
$1.9 million
of letters of credit outstanding and
$453.1 million
of borrowing capacity under our Revolving Credit Facility.
The Company's credit agreement requires that we maintain the following
two
financial ratios:
•
a working capital ratio, which is the ratio of consolidated current assets (includes unused commitments under its Revolving Credit Facility and excludes restricted cash and derivative assets) to consolidated current liabilities (excluding the current portion of long-term debt under the Revolving Credit Facility and derivative liabilities), of not less than
1.0
to 1.0;
•
a leverage ratio, which is the ratio of the sum of all of the Company’s debt to the consolidated EBITDAX (as defined in the credit agreement) for the four fiscal quarters then ended, of not greater than
4.25
to 1.0.
Our credit agreement also contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make loans to others, make investments, enter into mergers, make or declare dividends, enter into commodity hedges exceeding a specified percentage or our expected production, enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness, incur liens, sell assets, enter into transactions with affiliates or engage in certain other transactions without the prior consent of the lenders.
The Company was in compliance with such covenants and ratios as of
March 31, 2018
.
Principal amounts borrowed under our Revolving Credit Facility are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing at a Eurodollar rate or at the adjusted base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted London Interbank Offered Rate (“LIBOR”) (equal to the quotient of: (i) the LIBOR rate; divided by (ii) a percentage equal to
100%
minus the maximum rate on such date at which the administrative agent is required to maintain reserves on “Eurocurrency Liabilities,” as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from
150
basis points to
250 basis points
, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s referenced rate; (ii) the federal funds effective rate plus
50 basis points
; and (iii) the adjusted LIBOR rate plus
100 basis points
, plus an applicable margin ranging from
50
basis points to
150 basis points
, depending on the percentage of our borrowing base utilized, plus a commitment fee ranging from
37.5 basis points
to
50 basis points
charged on the undrawn commitment amount. On
March 31, 2018
, our weighted average interest rate was approximately
3.9%
.
2025 Senior Notes
On December 27, 2016, the Company issued
$450.0 million
of
5.25%
senior unsecured notes at par through a private placement. In November 2017, the Company exchanged these notes for registered notes with the same terms. The 2025 Senior Notes will mature on January 15, 2025. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are effectively subordinated in rights to our assets constituting collateral held by all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including indebtedness under our Revolving Credit Facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on the 2025
Senior Notes is payable semi-annually on January 15 and July 15. On or after January 15, 2020, the Company may redeem some or all of the 2025 Senior Notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of
103.938%
of principal, declining in twelve-month intervals to
100%
in 2023 and thereafter. In addition, prior to January 15, 2020, on any one or more occasions, the Company may redeem all or part of the 2025 Senior Notes at a redemption price of
100%
of the principal amount of the notes redeemed, plus an applicable make-whole premium along with accrued and unpaid interest.
In the event of certain changes in control of the Company, each holder of the 2025 Senior Notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to
101%
of the principal amount, plus accrued and unpaid interest to the date of purchase. The 2025 Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. The subsidiary guarantees are full and unconditional and joint and several, and any of our subsidiaries other than the subsidiary guarantors are minor. RSP Inc. does not have independent assets or operations. The terms of the notes include, among other restrictions, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. The Company was in compliance with the provisions of the indenture governing the 2025 Senior Notes as of
March 31, 2018
.
2022 Senior Notes
On September 26, 2014, the Company issued
$500.0 million
of
6.625%
senior unsecured notes at par through a private placement. In June 2015, the Company exchanged these notes for registered notes with the same terms. On August 10, 2015, the Company issued an additional
$200.0 million
of the
6.625%
senior unsecured notes at
99.25%
of the principal amount through a private placement. In March 2016, the Company exchanged these additional notes for registered notes with the same terms. The 2022 Senior Notes will mature on October 1, 2022. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our Revolving Credit Facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on the 2022 Senior Notes is payable semi-annually on April 1 and October 1. The Company may redeem some or all of the notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of
104.969%
of principal, declining in twelve-month intervals to
100%
in 2020 and thereafter.
In the event of certain changes in control of the Company, each holder of the 2022 Senior Notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to
101%
of the principal amount, plus accrued and unpaid interest to the date of purchase. The 2022 Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. The terms of the notes include, among other restrictions, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. The Company was in compliance with the provisions of the indenture governing the 2022 Senior Notes as of
March 31, 2018
.
NOTE 7—COMMITMENTS AND CONTINGENCIES
Legal and Environmental Matters
The Company is party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to any such proceedings or claims will not have a material adverse effect, individually or in the aggregate, on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future results of operations. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then-current status of the matters.
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed as incurred. We have established procedures for the ongoing evaluation of our operations to identify potential environmental exposures and to comply with regulatory policies and procedures.
Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when we determine the potential exposure related to, but not limited to, legal matters, environmental assessments and/or clean-ups, is probable and estimable. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both
March 31, 2018
and
December 31, 2017
, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Contractual Obligations
For the three months ended
March 31, 2018
, the Company had no material changes in its contractual commitments and obligations from amounts listed in Note 7 in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended
December 31, 2017
.
NOTE 8—EQUITY-BASED COMPENSATION
The Company's 2014 Long Term Incentive Plan ("LTIP") provides for granting restricted stock awards and performance-based restricted stock awards to employees, consultants and directors of the Company and its affiliates who perform services for the Company. Equity-based compensation expense, which was recorded in general and administrative expenses, was
$5.3 million
and
$3.9 million
for the
three months ended March 31, 2018
and
2017
, respectively.
Restricted Stock Awards
The following table represents restricted stock award activity for the
three months ended March 31,
2018:
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted Average Fair Value
|
Restricted shares outstanding, beginning of period
|
|
687,277
|
|
|
$
|
32.04
|
|
Restricted shares granted
|
|
437,608
|
|
|
35.96
|
|
Restricted shares canceled
|
|
(770
|
)
|
|
30.66
|
|
Restricted shares vested
|
|
(320,001
|
)
|
|
30.04
|
|
Restricted shares outstanding, end of period
|
|
804,114
|
|
|
$
|
34.97
|
|
As of
March 31, 2018
, the Company had unrecognized compensation expense of
$26.3 million
related to restricted stock awards which is expected to be recognized over a weighted average period of
2.2
years.
Performance-Based Restricted Stock Awards
We granted performance-based restricted stock awards to certain officers of the Company. The payout of these awards varies depending on the Company’s total shareholder return in comparison to an identified peer group. We granted
496,537
performance-based restricted stock awards in February 2018 that allow for a payout between
0%
and
100%
, with a cliff vesting period of
three
years.
The following table represents performance-based restricted stock award activity for the
three months ended March 31,
2018:
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted Average Fair Value
|
Restricted shares outstanding, beginning of period
|
|
1,001,079
|
|
|
$
|
21.14
|
|
Restricted shares granted (1)
|
|
496,537
|
|
|
23.96
|
|
Restricted shares vested (1)
|
|
(143,824
|
)
|
|
31.74
|
|
Restricted shares outstanding, end of period
|
|
1,353,792
|
|
|
$
|
21.05
|
|
(1) Performance-based restricted shares granted or vested reflect the number of shares granted or vested at a
100%
of the target payout. The actual payout of the shares granted may be between
0%
and
200%
depending on the date of the grant and Company’s total shareholder return in comparison to an identified peer group.
As of
March 31, 2018
, the Company had unrecognized compensation expense of
$19.4 million
related to performance-based restricted stock awards which is expected to be recognized over a weighted average period of
1.8
years.
NOTE 9—EARNINGS PER SHARE
The Company’s basic earnings per share amounts have been computed using the two-class method based on the weighted-average number of shares of common stock outstanding for the period. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
(in thousands, except per share data)
|
|
2018
|
|
2017
|
Numerator:
|
|
|
|
|
|
Net income available to stockholders
|
|
$
|
89,573
|
|
|
$
|
38,934
|
|
Basic net income allocable to participating securities (1)
|
|
448
|
|
|
195
|
|
Income available to stockholders
|
|
$
|
89,125
|
|
|
$
|
38,739
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
Weighted average number of common shares outstanding - basic
|
|
157,119
|
|
|
146,054
|
|
Effect of dilutive securities:
|
|
|
|
|
|
Restricted stock
|
|
1,190
|
|
|
951
|
|
Weighted average number of common shares outstanding - diluted
|
|
158,309
|
|
|
147,005
|
|
|
|
|
|
|
|
|
Net earnings per share:
|
|
|
|
|
|
|
Basic
|
|
$
|
0.57
|
|
|
$
|
0.27
|
|
Diluted
|
|
$
|
0.57
|
|
|
$
|
0.26
|
|
(1)
Restricted share awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.