Centennial Resource Development, Inc. - FORM 8-K/A

Centennial Resource Development, Inc. - FORM 8-K/A - November 10, 2016

Attached files

Attached files

Centennial Resource Development, Inc. Reports

file	filename
EX-99.2 - EXHIBIT 99.2 - Centennial Resource Development, Inc.	exhibit992.htm
EX-99.1 - EXHIBIT 99.1 - Centennial Resource Development, Inc.	exhibit991.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 10, 2016 (October 11, 2016)

Centennial Resource Development, Inc.

(Exact name of registrant as specified in its charter)



Delaware	001-37697	47- 5381253
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS. Employer Identification No.)

1401 Seventeenth Street, Suite 1000
Denver, Colorado 80202
(Address of principal executive offices, including zip code)

(720) 441-5515
(Registrant’s telephone number, including area code)

N/A
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Introductory Note

On October 11, 2016 (the “Closing Date”), Centennial Resource Development, Inc. (formerly known as Silver Run Acquisition Corporation) (the “Company”) consummated the previously announced acquisition of approximately 89% of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP”), pursuant to (i) that certain Contribution Agreement, dated as of July 6, 2016 (as amended by Amendment No. 1 thereto, dated as of July 29, 2016, the “Contribution Agreement”), among Centennial Resource Development, LLC, a Delaware limited liability company (“CRD”), NGP Centennial Follow-On LLC, a Delaware limited liability company (“NGP Follow-On”), Celero Energy Company, LP, a Delaware limited partnership (together with CRD and NGP Follow-On, the “Centennial Contributors”), CRP and New Centennial, LLC, a Delaware limited liability company (“NewCo”), (ii) that certain Assignment Agreement, dated as of October 7, 2016, between NewCo and Silver Run Acquisition Corporation and (iii) that certain Joinder Agreement, dated as of October 7, 2016, by Silver Run Acquisition Corporation. We refer to the acquisition and the other transactions contemplated by the Contribution Agreement as the “Business Combination.”

In connection with the closing of the Business Combination (the “Closing”), the Company changed its name from Silver Run Acquisition Corporation to Centennial Resource Development, Inc. Unless the context otherwise requires, “Silver Run” refers to the registrant prior to the Closing, and “we,” “us,” “our” and the “Company” refer to the registrant and its subsidiaries following the Closing.

This Amendment No. 1 on Form 8-K/A (the “Amendment”) amends the Form 8-K the Company filed on October 11, 2016 (the “Original 8-K”). Because the Business Combination occurred after the end of the third quarter of Silver Run and CRP, this Amendment provides information relating to CRP for the three and nine months ended September 30, 2016, including: (i) an updated Management’s Discussion and Analysis of Financial Condition and Results of Operations of CRP comparing the three and nine months ended September 30, 2016 to the three and nine months ended September 30, 2015, respectively; (ii) unaudited condensed consolidated financial statements of CRP for the nine months ended September 30, 2016 and (iii) an unaudited pro forma condensed balance sheet as of September 30, 2016 and the unaudited pro forma condensed combined statements of operations for the three and nine months ended September 30, 2016 of Silver Run and CRP after giving effect to the Business Combination and the related financing transactions.

No attempt has been made in this Amendment to modify or update any other disclosures presented in the Original 8-K.

Item 2.01. Completion of Acquisition or Disposition of Assets.

The disclosure set forth under “Introductory Note” above is incorporated in this Item 2.01 by reference. The material provisions of the Contribution Agreement are described in Silver Run’s Proxy Statement dated September 23, 2016, relating to the special meeting of Silver Run’s stockholders, in the section entitled “Proposal No. 1—Approval of the Business Combination—Contribution Agreement,” which is incorporated by reference herein.

Financial Statements

The unaudited condensed consolidated financial statements of CRP as of September 30, 2016 and for the three and nine months ended September 30, 2016 are included as Exhibit 99.1 to this Amendment.

Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Amendment may constitute “forward-looking statements” for purposes of the federal securities laws. All statements, other than statements of historical fact included in this Amendment, regarding CRP's strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Amendment, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” in the Company's Registration Statement on Form S-1 (Registration No. 333-214355) filed with the Securities and Exchange Commission on October 31, 2016 (the “Registration Statement”) beginning on page 8.

Forward-looking statements may include statements about:


•	CRP's business strategy;


•	CRP's reserves;


•	CRP's drilling prospects, inventories, projects and programs;


•	CRP's ability to replace the reserves it produces through drilling and property acquisitions;


•	CRP's financial strategy, liquidity and capital required for its development program;


•	CRP's realized oil, natural gas and natural gas liquids (“NGL”) prices;


•	the timing and amount of CRP's future production of oil, natural gas and NGLs;


•	CRP's hedging strategy and results;


•	CRP's future drilling plans;


•	CRP's competition and government regulations;


•	CRP's ability to obtain permits and governmental approvals;


•	CRP's pending legal or environmental matters;


•	CRP's marketing of oil, natural gas and NGLs;


•	CRP's leasehold or business acquisitions;


•	CRP's costs of developing its properties;


•	general economic conditions;


•	credit markets;


•	uncertainty regarding CRP's future operating results; and


•	CRP's plans, objectives, expectations and intentions contained in this Amendment that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond CRP's control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors” in the Registration Statement beginning on page 8.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Amendment occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Amendment are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on CRP's behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Amendment.

Glossary of Oil and Natural Gas Terms

The following are abbreviations and definitions of certain terms used in this Amendment, which are commonly used in the oil and natural gas industry.

Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.

Boe. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Boe/d. One Boe per day.

Btu. The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).

Development project. The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).

Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. For a complete definition of exploration costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(12).

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Gross wells. The total wells in which a working interest is owned.

MBbl. One thousand barrels of crude oil, condensate or NGLs.

MBoe. One thousand Boe.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One Mcf per day.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

NGLs. Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

NYMEX. The New York Mercantile Exchange.

Operator. The individual or company responsible for the development and/or production of an oil or natural gas well or lease.

PV-10. The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved properties. Properties with proved reserves.

Proved reserves. Those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator

must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

Realized price. The cash market price less all expected quality, transportation and demand adjustments.

Reasonable certainty. A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resources. Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Royalty. An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Service well. A well drilled or completed for the purpose of supporting production in an existing field.

Spot market price. The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized measure. Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

Unproved properties. Properties with no proved reserves.

Wellbore. The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

Working interest. The right granted to the lessee of a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

Workover. Operations on a producing well to restore or increase production.

WTI. West Texas Intermediate.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the accompanying financial statements and related notes of CRP included as Exhibit 99.1 to this Amendment. The following discussion contains forward-looking statements that reflect CRP’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside CRP’s control. CRP’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not

limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in “Risk Factors” in the Registration Statement and elsewhere in this Amendment, particularly in “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

CRP is an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. CRP's assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin.

Recent significant events that occurred in October 2016 include the following:


•	On October 11, 2016, the Company consummated the previously announced acquisition of approximately 89% of the outstanding membership interests in CRP.


•	The Company fully repaid $189 million of outstanding debt of CRP at the closing of the acquisition.


•	CRP amended its credit agreement to increase the borrowing base under the revolving credit facility from $140 million to $200 million, leaving $199.6 million in borrowing capacity, net of $0.4 million of outstanding letters of credit at the closing.

CRP's financial and operating performance and significant events for the third quarter of 2016 include the following highlights:


•	Average daily production totaled 8,903 barrels of oil equivalents ("Boe") per day and CRP's average daily oil production was 6,109 barrels per day, representing approximately 69% of total production.


•	Revenue for the quarter totaled $27.3 million, with oil revenues representing approximately 86% of total revenues.


•	Average realized oil price was $41.62 per barrel, excluding the impact of commodity derivative transactions.


•	Lease operating costs, including workover expenses, totaled $3.7 million for the quarter or $4.46 per Boe.


•	CRP had one rig running for most of the third quarter, spudded four wells and completed two wells. The completed wells had an average effective lateral length of 4,496’ and an average field estimate cost of $5.1 million. These wells averaged 17 days from spud to total depth.


•	CRP incurred capital costs of approximately $24 million, excluding leasing and acquisition costs, during the third quarter.


•	During the third quarter, CRP completed its third party crude midstream system and is now piping the majority of its crude to either Midland or Crane, Texas.

Market Conditions

The oil and gas industry is cyclical and commodity prices can be volatile. In the second half of 2014, oil prices began a rapid and significant decline as global and domestic supply began to outpace demand. During 2015 and through the first quarter of 2016, global and domestic oil supply continued to outpace demand resulting in further deterioration in realized oil prices. Thus far in 2016, oil prices have been volatile, and it is likely that oil prices will continue to fluctuate due to the ongoing global supply and demand imbalance, high inventories and geopolitical factors.

CRP's revenue, profitability and future growth are highly dependent on the price it receives for its oil and natural gas production, as well as NGLs that are extracted from its natural gas during processing. Compared to 2014, CRP's realized oil price for 2015 fell 47.3% to $42.43 per barrel, and its realized oil price for the first nine months of 2016 has further decreased to $37.48 per barrel. Similarly, CRP's realized natural gas price for 2015 dropped 43.2% to $2.60 per Mcf and its realized price for NGLs declined 52.2% to $14.66 per barrel. For the first nine months of 2016, CRP's realized price for natural gas was $2.24 per Mcf and its realized price for NGLs was $12.80 per barrel. Lower oil, natural gas and NGL prices not only may decrease CRP's revenues, but also may reduce the amount of oil, natural gas and NGLs that it can produce economically and therefore potentially lower CRP's oil, natural gas and NGL reserves.

Lower commodity prices in the future could result in property impairments and may materially and adversely affect CRP's future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned capital expenditures. Lower oil, natural gas and NGL prices may also reduce the borrowing base under CRP's credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of its proved reserves that have been mortgaged to the lenders. Alternatively, higher oil and natural gas prices may result in significant non-cash fair value losses being incurred on its derivatives, which could cause it to experience net losses when oil and natural gas prices rise.

How CRP Evaluates Its Operations

CRP uses a variety of financial and operational metrics to assess the performance of its oil and natural gas operations, including:


•	realized prices on the sale of oil, natural gas and NGLs, including the effect of CRP’s commodity derivative contracts on its oil and natural gas production;


•	production results;


•	lease operating expenses; and


•	Adjusted EBITDAX ⁽¹⁾.


(1)	Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States (“GAAP”). Please see "Non-GAAP Financial Measure" below for a reconciliation.

Revenues

CRP’s revenues are derived from the sale of its oil and natural gas production, as well as the sale of NGLs that are extracted from its natural gas during processing. Oil sales contributed 87% of CRP’s total revenues for the first nine months of 2016. Natural gas sales contributed 9% and NGL sales contributed 5% of CRP’s total revenues for the first nine months of 2016. CRP's oil, natural gas and NGL revenues do not include the effects of commodity derivative contracts.

Increases or decreases in CRP’s revenue, profitability and future production growth are highly dependent on the commodity prices it receives. Oil, natural gas and NGL prices are market driven and have been historically volatile, and CRP expects that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors. See "—Market Conditions" for information regarding the current commodity price environment. A $1.00 per barrel change in CRP’s realized oil price would have resulted in a $1.5 million change in oil revenues for the first nine months of 2016. A $0.10 per Mcf change in CRP’s realized natural gas price would have resulted in a $0.3 million change in its natural gas revenues for the first nine months of 2016. A $1.00 per barrel change in NGL prices would have changed NGL revenue by $0.2 million for the first nine months of 2016.

The following table presents CRP’s average realized commodity prices, as well as the effects of derivative settlements.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Crude Oil (per Bbl):
Average NYMEX price	$	44.94	$	46.50	$	41.53	$	51.02
Average realized price, before the effects of derivative settlements	41.62		42.31		37.48		44.45
Effects of derivative settlements	3.47		19.99		10.94		18.85
Natural Gas:
Average NYMEX price (per MMBtu)	$	2.79	$	2.73	$	2.35	$	2.76
Average realized price, before the effects of derivative settlements (per Mcf)	2.67		2.85		2.24		2.76
Effects of derivative settlements (per Mcf)	—		0.35		—		0.42
NGLs (per Bbl):
Average realized price	$	14.02	$	10.89	$	12.80	$	14.83

While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within CRP's industry, the prices it receives are affected by quality, energy content, location and transportation differentials for these products.

See “—Results of Operations” below for an analysis of the impact changes in realized prices had on CRP’s revenues.

Operating Costs and Expenses

Costs associated with producing oil, natural gas and NGLs are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells CRP owns. As of September 30, 2016 and December 31, 2015, CRP owned interests in 147 and 138 gross wells, respectively.

Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, materials and supplies comprise the most significant portion of CRP's LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to CRP’s pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain of CRP’s operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, CRP incurs power costs in connection with various production-related activities, such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with its oil and natural gas production.

CRP monitors its operations to ensure that it is incurring LOE at an acceptable level. For example, CRP monitors its LOE per Boe to determine if any wells or properties should be shut in, recompleted or sold. This unit rate also allows CRP to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers. Although CRP strives to reduce its LOE, these expenses can increase or decrease on a per unit basis as a result of various factors as CRP operates its properties or makes acquisitions and dispositions of properties. For example, CRP may increase field level expenditures to optimize its operations, incurring higher expenses in one quarter relative to another, or it may acquire or dispose of properties that have different LOE per Boe. These initiatives would influence CRP’s overall operating cost and could cause fluctuations when comparing LOE on a period to period basis.

Severance and Ad Valorem Taxes. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the severance taxes CRP pays correlate to the changes in oil, natural gas and NGLs revenues. CRP is also subject to ad valorem taxes in the counties where its production is located. Ad valorem taxes are generally based on the valuation of CRP’s oil and natural gas properties, which also trend with oil and natural gas prices.

Transportation, Processing, Gathering and Other Operating Expenses. Transportation, processing, gathering and other operating expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and gas processing costs. These costs will fluctuate with increases or decreases in production volumes, contractual fees and changes in fuel and compression costs.

Depreciation, Depletion, Amortization, and Accretion of Asset Retirement Obligations. Depreciation, depletion, amortization, and accretion of asset retirement obligations (“DD&A”) is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. CRP uses the successful efforts method of accounting for oil and natural gas activities and, as such, it capitalizes all costs associated with its development and acquisition efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method. Please read “—Critical Accounting Policies and Estimates—Successful Efforts Method of Accounting for Oil and Natural Gas Activities” for further discussion.

Impairment Expense. CRP reviews its proved properties and unproved leasehold costs for impairment whenever events and changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Please read “—Critical Accounting Policies and Estimates—Impairment” for further discussion.

General and Administrative Expenses. General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for CRP’s corporate staff, costs of maintaining its headquarters, costs of managing its production and development operations, audit and other fees for professional services and legal compliance.

Interest Expense. CRP finances a portion of its working capital requirements and capital expenditures with borrowings under its revolving credit facility and term loan. As a result, CRP incurs interest expense that is affected by both fluctuations in interest rates and its financing decisions. CRP reflects interest paid to the lenders under its revolving credit facility and term loan in interest expense.

Derivative Gain (Loss). Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. CRP has not elected to apply cash flow hedge accounting, and consequently, recognizes gains and losses in earnings rather than deferring such amounts in other comprehensive income as allowed under cash flow hedge accounting. Fair value gains or losses, as well as cash receipts or payments on settled derivative contracts, are recognized in CRP’s statements of operations. Cash flows from derivatives are reported as cash flows from operating activities.

A discussion of changes in operating costs and expenses is included in Results of Operations, below.

Non-GAAP Financial Measure

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of CRP's financial statements, such as industry analysts, investors, lenders and rating agencies. Management defines Adjusted EBITDAX as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization and accretion of asset retirement obligations, abandonment expense and impairment of unproved properties, (gains) losses on derivatives excluding net cash receipts (payments) on settled derivatives, non-cash equity based compensation, gains and losses from the sale of assets and other non-cash and non-recurring operating items. Adjusted EBITDAX is not a measure of net income as determined by U.S. GAAP.

Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate CRP's operating performance and compare the results of its operations from period to period and against its peers without regard to its financing methods or capital structure. Management excludes the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within CRP's industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with U.S. GAAP or as an indicator of CRP's operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Management's presentation of Adjusted EBITDAX should not be construed as an inference that CRP's results will be unaffected by unusual or non-recurring items. Managements computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDAX to net income, the most directly comparable financial measure calculated and presented in accordance with U.S. GAAP:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)
Adjusted EBITDAX reconciliation to net income:
Net income (loss)	$	(5,134	)	$	3,326		$	(35,727	)	$	(25,282	)
Interest expense	1,983			1,469			5,422			4,743
Income tax benefit	—			—			(406		)	—
Depreciation, depletion and amortization and accretion of asset retirement obligations	18,454			19,880			60,939			64,003
Abandonment expense and impairment of unproved properties	1,649			—			2,546			3,851
Loss (gain) on derivatives	(1,741		)	(13,344		)	4,184			(12,320		)
Net cash receipts on settled derivatives	1,952			9,185			16,623			25,972
Contract termination and rig stacking	—			221			—			2,388
Gain on sale of assets	(15		)	(9		)	(11		)	(2,688		)
Adjusted EBITDAX	$	17,148		$	20,728		$	53,570		$	60,667

Results of Operations

Three Months Ended September 30, 2016 Compared to September 30, 2015

Oil, Natural Gas and NGL Sales Revenues. The following table provides the components of CRP's revenues for the periods indicated, as well as each period’s average prices and production volumes:



	Three Months Ended September 30,
	2016		2015		Change			% Change
Revenues (in thousands):
Oil sales	$	23,388	$	18,913	$	4,475		24	%
Natural gas sales	2,629		2,054		575			28	%
NGL sales	1,304		926		378			41	%
Total Revenues	$	27,321	$	21,893	$	5,428		25	%
Average sales price (1):
Oil (per Bbl)	$	41.62	$	42.31	$	(0.69	)	(2	)%
Natural gas (per Mcf)	2.67		2.85		(0.18		)	(6	)%
NGL (per Bbl)	14.02		10.89		3.13			29	%
Total (per Boe)	$	33.36	$	33.58	$	(0.22	)	(1	)%
Production:
Oil (MBbls)	562		447		115			26	%
Natural gas (MMcf)	984		721		263			36	%
NGLs (MBbls)	93		85		8			9	%
Total (MBoe)(2)	819		652		167			26	%
Average daily production volume:
Oil (Bbls/d)	6,109		4,859		1,250			26	%
Natural gas (Mcf/d)	10,696		7,837		2,859			36	%
NGLs (Bbls/d)	1,011		924		87			9	%
Total (Boe/d)(2)	8,903		7,089		1,814			26	%

(1) Average prices shown in the table reflect prices before the effects of CRP's realized commodity derivative transactions.

(2) Total may not sum or recalculate due to rounding.

As reflected in the table above, CRP's total revenues for the third quarter of 2016 were 25%, or $5.4 million, higher than total revenues for the third quarter of 2015. The increase was primarily due to a 26% increase in production.

Oil sales increased 24%, or $4.5 million, primarily due to a 26% increase in oil volumes sold, offset by a 2% decrease in the average sales price. Natural gas sales increased 28%, or $0.6 million, primarily due to a 36% increase in natural gas volumes sold, partially offset by a 6% decrease in average sales price. NGL sales increased 41% or $0.4 million, primarily due to an 29% increase in the average sales price accompanied by a 9% increase in NGL volumes sold.

Operating Expenses. CRP presents per Boe information because it uses this information to evaluate its performance relative to its peers and to identify and measure trends it believes may require additional analysis.

The following table summarizes CRP's operating expenses for the periods indicated:



	Three Months Ended September 30,
	2016			2015			Change			% Change
Operating Expenses (in thousands):
Lease operating expenses	$	3,656		$	4,355		$	(699	)	(16	)%
Severance and ad valorem taxes	1,432			1,555			(123		)	(8	)%
Transportation, processing, gathering and other operating expense	1,787			1,424			363			25	%
Depreciation, depletion, amortization and accretion of asset retirement obligations	18,454			19,880			(1,426		)	(7	)%
Abandonment expense and impairment of unproved properties	1,649			—			1,649			100	%
Contract termination and rig stacking	—			221			(221		)	(100	)%
General and administrative expenses	5,250			3,007			2,243			75	%
Total operating expenses before gain on oil and natural gas properties	32,228			30,442			1,786			6	%
Gain on sale of oil and natural gas properties	(15		)	(9		)	(6		)	67	%
Total operating expenses after gain on oil and natural gas properties	$	32,213		$	30,433		$	1,780		6	%
Expenses per Boe:
Lease operating expenses	$	4.46		$	6.68		$	(2.22	)	(33	)%
Severance and ad valorem taxes	1.75			2.38			(0.63		)	(26	)%
Transportation, processing, gathering and other operating expense	2.18			2.18			—			—	%
Depreciation, depletion, amortization and accretion of asset retirement obligations	22.53			30.49			(7.96		)	(26	)%
Abandonment expense and impairment of unproved properties	2.01			—			2.01			100	%
Contract termination and rig stacking	—			0.34			(0.34		)	(100	)%
General and administrative expenses	6.41			4.61			1.80			39	%
Total operating expenses per Boe	$	39.34		$	46.68		$	(7.34	)	(16	)%

Lease Operating Expenses. CRP experiences volatility in its LOE as a result of the impact industry activity has on service provider costs and seasonality in workover expense. LOE decreased 16%, or $0.7 million, in the three months ended September 30, 2016 compared to the prior year period due in part to service providers lowering costs in light of the weak commodity price environment. Additionally, CRP shut in several non-economic wells at the beginning of 2016, which decreased LOE by approximately $0.5 million. Workover expense decreased $0.4 million in the three months ended September 30, 2016 and CRP converted several rental units to permanent pumping units decreasing the amounts of rental expense by approximately $0.5 million in the three months ended September 30, 2016.

Severance and Ad Valorem Taxes. Severance taxes are primarily based on the market value of CRP's production at the wellhead and ad valorem taxes are generally based on the valuation of CRP's oil and natural gas properties and vary across the different counties in which it operates. Severance and ad valorem taxes decreased 8%, or $0.1 million, in the three months ended September 30, 2016 compared to the prior year period. Severance and ad valorem taxes as a percentage of CRP's revenue were 5.2% for the three months ended September 30, 2016 compared to a higher 7.1% for the prior year period.

Transportation, Processing, Gathering and Other Operating Expenses. Transportation, processing, gathering and other operating expenses increased 25%, or $0.4 million, in the three months ended September 30, 2016 compared to the prior year period. The increase was mainly driven by higher production revenues due to a 26% increase in the average sales volumes, which resulted in higher costs associated with fuel and processing fees.

Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations. CRP's DD&A rate can fluctuate as a result of impairments, dispositions, finding and development costs and proved reserve volumes. DD&A decreased 7%, or $1.4 million, for the three months ended September 30, 2016 compared to the prior year period. The decrease was primarily due to a decrease in the DD&A rate, partially offset by an increase in average production volumes. The decrease in the DD&A rate was mainly due to lower drilling costs, in conjunction with lower LOE that extend the economic lives of CRP's wells. DD&A per Boe was $22.53 for the three months ended September 30, 2016 compared to $30.49 for the prior year period.

Abandonment Expense and Impairment of Unproved Properties. In the three months ended September 30, 2016 and 2015, CRP recorded $1.6 million and $0.0 million, respectively, of abandonment expense attributable to leases that expired during the period or that it expects to expire in the future.

Contract Termination and Rig Stacking. In the three months ended September 30, 2016, CRP did not incur any drilling and rig termination fees, as compared to $0.2 million in the prior year period. In light of the low commodity price environment, CRP curtailed drilling activity beginning in the first quarter of 2015, and as a result, it incurred the $0.2 million of drilling and rig termination fees in the third quarter of 2015.

General and Administrative Expenses. G&A expenses increased 75%, or $2.2 million, primarily due to an increase in transaction costs and miscellaneous expenses of $1.1 million and $1.2 million, respectively, in the three months ended September 30, 2016 compared to the prior year period. G&A per Boe was $6.41 for the three months ended September 30, 2016 compared to $4.61 for the prior year period. The increase in G&A per Boe was due to an increase in expenses, partially offset by an increase in production during the third quarter 2016 compared to the third quarter of 2015.

Gain on Sale of Oil and Natural Gas Properties. In the three months ended September 30, 2016 and September 30, 2015, CRP recorded an immaterial net gain on the sale of oil and natural gas properties.

Other Income and Expenses. The following table summarizes CRP's other income and expenses for the periods indicated:



	Three Months Ended September 30,
	2016			2015			Change			% Change
Other (expense) income (in thousands):
Interest expense	$	(1,983	)	$	(1,469	)	(514		)	35	%
Gain on derivative instruments	1,741			13,344			(11,603		)	(87	)%
Other expense	—			(9		)	9			(100	)%
Total other (expense) income	$	(242	)	$	11,866		$	(12,108	)	(102	)%
Income tax expense	$	—		$	—		$	—		100	%

Interest Expense. Interest expense increased 35%, or $0.5 million, primarily due to an increase in the average borrowings under CRP's revolving credit facility during the three months ended September 30, 2016 compared to the prior year period.

Gain on Derivative Instruments. For the three months ended September 30, 2016, CRP recognized a $1.7 million derivative gain as compared to a $13.3 million derivative gain in the prior year period. Net losses and gains on CRP's derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

Nine Months Ended September 30, 2016 Compared to September 30, 2015

Oil, Natural Gas and NGL Sales Revenues. The following table provides the components of CRP's revenues for the periods indicated, as well as each period’s average prices and production volumes:



	Nine Months Ended September 30,
	2016		2015		Change			% Change
Revenues (in thousands):
Oil sales	$	56,975	$	59,068	$	(2,093	)	(4	)%
Natural gas sales	5,717		6,082		(365		)	(6	)%
NGL sales	3,097		3,590		(493		)	(14	)%
Total Revenues	$	65,789	$	68,740	$	(2,951	)	(4	)%
Average sales price (1):
Oil (per Bbl)	$	37.48	$	44.45	$	(6.97	)	(16	)%
Natural gas (per Mcf)	2.24		2.76		(0.52		)	(19	)%
NGL (per Bbl)	12.80		14.83		(2.03		)	(14	)%
Total (per Boe)	$	30.08	$	35.45	$	(5.37	)	(15	)%
Production:
Oil (MBbls)	1,520		1,329		191			14	%
Natural gas (MMcf)	2,551		2,205		346			16	%
NGLs (MBbls)	242		242		—			—	%
Total (MBoe)(2)	2,187		1,939		248			13	%
Average daily production volume:
Oil (Bbls/d)	5,547		4,868		679			14	%
Natural gas (Mcf/d)	9,310		8,077		1,233			15	%
NGLs (Bbls/d)	883		886		(3		)	—	%
Total (Boe/d)(2)	7,982		7,101		881			12	%

(1) Average prices shown in the table reflect prices before the effects of CRP's realized commodity derivative transactions.

(2) Total may not sum or recalculate due to rounding.

As reflected in the table above, CRP's total revenues for the first nine months of 2016 were 4%, or $3.0 million, lower than total revenues for the first nine months of 2015. The decrease was primarily due to a decrease in commodity prices, resulting in a 15% decrease in average sales price per Boe, which was partially offset by a 13% increase in production sold in the first nine months of 2016 compared to the prior year.

Oil sales decreased 4%, or $2.1 million, for the first nine months of 2016 compared to the prior year period primarily due to a 16% decrease in the average sales price for oil, partially offset by a 14% increase in oil volumes sold. Natural gas sales decreased 6%, or $0.4 million, for the first nine months of 2016 compared to the prior year period primarily due to a 19% decrease in the average sales price for natural gas, partially offset by a 16% increase in natural gas volumes sold. NGL sales decreased 14%, or $0.5 million, for the first nine months of 2016 compared to the prior year period primarily due to a 14% decrease in the average sales price for NGLs.

The following table summarizes CRP's operating expenses for the periods indicated:



	Nine Months Ended September 30,
	2016			2015			Change			% Change
Operating Expenses (in thousands):
Lease operating expenses	$	10,295		$	17,317		$	(7,022	)	(41	)%
Severance and ad valorem taxes	3,523			3,833			(310		)	(8	)%
Transportation, processing, gathering and other operating expense	4,375			4,352			23			1	%
Depreciation, depletion, amortization and accretion of asset retirement obligations	60,939			64,003			(3,064		)	(5	)%
Abandonment expense and impairment of unproved properties	2,546			3,851			(1,305		)	(34	)%
Contract termination and rig stacking	—			2,388			(2,388		)	(100	)%
General and administrative expenses	10,655			8,538			2,117			25	%
Total operating expenses before gain on oil and natural gas properties	92,333			104,282			(11,949		)	(11	)%
Gain on sale of oil and natural gas properties	(11		)	(2,688		)	2,677			(100	)%
Total operating expenses after gain on oil and natural gas properties	$	92,322		$	101,594		$	(9,272	)	(9	)%
Expenses per Boe:
Lease operating expenses	$	4.71		$	8.93		$	(4.22	)	(47	)%
Severance and ad valorem taxes	1.61			1.98			(0.37		)	(19	)%
Transportation, processing, gathering and other operating expense	2.00			2.24			(0.24		)	(11	)%
Depreciation, depletion, amortization and accretion of asset retirement obligations	27.86			33.01			(5.15		)	(16	)%
Abandonment expense and impairment of unproved properties	1.16			1.99			(0.83		)	(42	)%
Contract termination and rig stacking	—			1.23			(1.23		)	(100	)%
General and administrative expenses	4.87			4.40			0.47			11	%
Total operating expenses per Boe	$	42.21		$	53.78		$	(11.57	)	(22	)%

Lease Operating Expenses. CRP experiences volatility in its LOE as a result of the impact industry activity has on service provider costs and seasonality in workover expense. LOE decreased 41%, or $7.0 million, in the first nine months of 2016 compared to the first nine months of 2015, due in part to service providers lowering costs in light of the weak commodity price environment. Additionally, CRP shut in several non-economic wells at the beginning of 2016, which decreased LOE approximately $1.0 million. Workover expense decreased $2.1 million and CRP converted several rental units to permanent pumping units decreasing the amounts of rental expense by approximately $1.0 million in the first nine months of 2016 compared to the prior year period. Lastly, CRP decreased the use of contract labor and expenses related to repairs and maintenance by $1.3 million and $1.6 million, respectively, in the first nine months of 2016 compared to the first nine months of 2015.

Severance and Ad Valorem Taxes. Severance taxes are primarily based on the market value of CRP's production at the wellhead and ad valorem taxes are generally based on the valuation of its oil and natural gas properties and vary across the different counties in which it operates. Severance and ad valorem taxes decreased 8%, or $0.3 million, in the first nine months of 2016 compared to the first nine months of 2015, primarily due to lower production revenues, which were primarily a result of lower realized commodity prices. Severance and ad valorem taxes as a percentage of CRP's revenue were 5.4% for the first nine months of 2016 compared to 5.6% for the prior year period.

Transportation, Processing, Gathering and Other Operating Expenses. Transportation, processing, gathering and other operating expenses were relatively flat in the first nine months of 2016 compared to the first nine months of 2015.

Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations. CRP's DD&A rate can fluctuate as a result of impairments, dispositions, finding and development costs and proved reserve volumes. DD&A decreased 5%, or $3.1 million, in the first nine months of 2016 compared to the first nine months of 2015, primarily due to a decrease in the DD&A rate, partially offset by an increase in average production volumes. The decrease in the DD&A rate was primarily due to lower drilling costs, in conjunction with lower LOE that extends the economic lives of CRP's wells. DD&A per Boe was $27.86 for the first nine months of 2016 compared to $33.01 for the prior year period.

Abandonment Expense and Impairment of Unproved Properties. In the nine months ended September 30, 2016 and 2015, we recorded $2.5 million and $3.9 million, respectively, of abandonment expense attributable to leases that expired during the period or that CRP expects to expire in the future.

Contract Termination and Rig Stacking. In the first nine months of 2016, CRP did not incur any drilling and rig termination fees, as compared to $2.4 million in the first nine months of 2015. In light of the low commodity price environment, CRP curtailed drilling activity beginning in the first quarter of 2015, and as a result, incurred drilling and rig termination fees of $2.4 million in the first nine months of 2015.

General and Administrative Expenses. G&A expenses increased 25%, or $2.1 million, primarily due to an increase in transaction costs and miscellaneous expenses of $1.1 million each in the first nine months of 2016 compared to the first nine months of 2015. G&A per Boe was $4.87 for the first nine months of 2016 compared to $4.40 for the prior year period. The increase in G&A per Boe was primarily due to an increase in expenses, partially offset by an increase in production during the first nine months of 2016 compared to the first nine months of 2015.

Gain on Sale of Oil and Natural Gas Properties. In the first nine months of 2016, CRP recorded an immaterial net gain on the sale of oil and natural gas properties as compared to a net gain of $2.7 million in the prior year period, which was primarily attributable to a gain associated with the sale of non-core unproved property to an unrelated third party.

Other Income and Expenses. The following table summarizes CRP's other income and expenses for the periods indicated:



	Nine Months Ended September 30,
	2016			2015			Change			% Change
Other (expense) income (in thousands):
Interest expense	$	(5,422	)	$	(4,743	)	$	(679	)	14	%
Gain (loss) on derivative instruments	(4,184		)	12,320			(16,504		)	(134	)%
Other (expense) income	6			(5		)	11			(220	)%
Total other (expense) income	$	(9,600	)	$	7,572		$	(17,172	)	(227	)%
Income tax (expense) benefit	$	406		$	—		$	406		100	%

Interest Expense. Interest expense increased 14%, or $0.7 million, primarily due to an increase in the average borrowings under CRP's revolving credit facility during the first nine months of 2016 compared to the first nine months of 2015.

Gain on Derivative Instruments. In the first nine months of 2016, CRP recognized a $4.2 million derivative loss as compared to a $12.3 million derivative gain in the first nine months of 2015. Net losses and gains on its derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

Liquidity and Capital Resources

Overview

CRP's development and acquisition activities require it to make significant operating and capital expenditures. Historically, CRP's primary sources of liquidity have been capital contributions from its equity sponsors, borrowings under its revolving credit facility and term loan, proceeds from asset dispositions and cash flows from operations. To date, CRP's primary use of capital has been for the acquisition and development of oil and natural gas properties.

CRP's 2016 capital budget for drilling, completion and recompletion activities and facilities costs is approximately $92.0 million, excluding leasing and other acquisitions. In the nine months ended September 30, 2016, CRP incurred capital costs of approximately $48.9 million, excluding leasing and acquisition costs.

Because CRP is the operator of a high percentage of its acreage, the amount and timing of capital expenditures is largely discretionary. CRP could choose to defer a portion of these planned 2016 capital expenditures depending on a variety of factors, including the success of its drilling activities; prevailing and anticipated prices for oil, natural gas and NGLs; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the level of participation by other working interest owners.

Based upon current oil and natural gas price expectations for 2016, CRP believes that its cash flow from operations and additional borrowings under its revolving credit facility will provide CRP with sufficient liquidity to execute its current capital program.

However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop its properties. CRP cannot provide assurance that operations and other needed capital will be available on acceptable terms or at all. In the event CRP makes additional acquisitions and the amount of capital required is greater than the amount CRP has available for acquisitions at that time, CRP could be required to reduce the expected level of capital expenditures and/or seek additional capital. If CRP requires additional capital for that or other reasons, CRP may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. If CRP is unable to obtain funds when needed or on acceptable terms, CRP may be required to curtail its current drilling program, which could result in a loss of acreage through lease expirations. In addition, CRP may not be able to complete acquisitions that may be favorable to CRP or finance the capital expenditures necessary to maintain its production or replace its reserves.

Working Capital Analysis

CRP's working capital, which we define as current assets minus current liabilities, was a deficit of $11.6 million and a surplus of $12.0 million at September 30, 2016 and December 31, 2015, respectively. CRP's cash balances totaled $0.4 million and $1.8 million at September 30, 2016 and December 31, 2015, respectively. Due to the amounts that accrue related to CRP's drilling program, it may incur working capital deficits in the future. CRP expects that its cash flows from operating activities and availability under its credit agreement will be sufficient to fund its working capital needs. CRP expects that its pace of development, production volumes, commodity prices and differentials to NYMEX prices for its oil and natural gas production will be the largest variables affecting its working capital.

Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2016 and September 30, 2015

The following table summarizes CRP's cash flows for the periods indicated:



	Nine Months Ended September 30,
	2016			2015
	(in thousands)
Net cash provided by operating activities	$	51,511		$	48,474
Net cash used in investing activities	(100,975		)	(171,316		)
Net cash provided by financing activities	48,106			110,219

Operating Activities. Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs, production volumes and changes in working capital. The increase in net cash provided by operating activities for the first nine months of 2016 compared to the first nine months of 2015 was primarily due to a $11.9 million reduction in operating expenses and a positive cash flow impact from working capital of $8.4 million, partially offset by a $3.0 million decrease in total revenues and a $9.3 million decrease in derivatives settlements.

Investing Activities. Net cash used in investing activities is primarily comprised of acquisition and development of oil and natural gas properties, net of dispositions. In the first nine months of 2016, net cash used for investing activities included $100.8 million attributable to the acquisition and development of oil and natural gas properties. In the first nine months of 2015, net cash used for investing activities included $171.9 million attributable to the acquisition and development of oil and natural gas properties.

Financing Activities. Net cash provided by financing activities in the first nine months of 2016 included $55.0 million of borrowings under CRP's revolving credit facility, offset by repayments of $5.0 million. Net cash provided by financing activities in the first nine months of 2015 included $110.7 million of capital contributions, which were primarily used to repay a portion of CRP's revolving credit facility.

CRP's Term Loan and Its Revolving Credit Facility

On October 15, 2014, CRP entered into an amended and restated credit agreement (as amended, the “credit agreement”) with JPMorgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders, that includes both a term loan commitment of $65.0 million (the “term loan”), which was fully funded as of September 30, 2016, and a revolving credit facility (CRP's “revolving credit facility”) with commitments of $500.0 million (subject to the borrowing base), with a sublimit for letters of credit of $15.0 million.

As of September 30, 2016, CRP had $124.0 million outstanding under its revolving credit facility and $0.5 million of letters of credit outstanding, and CRP was able to incur approximately $15.5 million of additional indebtedness under its revolving credit facility. CRP's term loan matures on April 15, 2018, and its revolving credit facility matures on October 15, 2019.

On October 11, 2016, CRP entered into an amendment to the credit agreement to, among other things (i) permit the Business Combination, (ii) reflect the repayment in full of all term loans thereunder, (iii) increase the borrowing base from $140.0 million to $200.0 million, (iv) increase the interest rate to LIBOR plus 2.25% - 3.25%, and (v) require CRP to have sufficient liquidity and satisfy a maximum leverage ratio in order to make dividends. As of the Closing Date, CRP had no outstanding debt and approximately $100.0 million of cash on hand.

The amount available to be borrowed under CRP's revolving credit facility is subject to a borrowing base that will be redetermined semiannually each April 1 and October 1 by the lenders in their sole discretion. CRP's credit agreement also allows, in 2016 and thereafter, for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumes of CRP's proved oil and natural gas reserves and estimated cash flows from these reserves and its commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under its credit agreement. The next regular redetermination date is scheduled for April 2017.

Principal amounts borrowed are payable on the term loan maturity date and the revolving credit maturity date, as applicable. Interest on the term loan is LIBOR plus 5.25%. At September 30, 2016, the weighted average interest rate on CRP's term loan was 5.78%. Loans under its revolving credit facility may be base rate loans or LIBOR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements) plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of the borrowing base utilized. At September 30, 2016, the weighted average interest rate on borrowings under CRP's revolving credit facility was approximately 2.78%. CRP also pays a commitment fee on unused amounts of its revolving credit facility ranging from 37.5 basis points to 50 basis points, depending on the percentage of the borrowing base utilized. CRP may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

CRP's credit agreement contains restrictive covenants that limit its ability to, among other things:


•	incur additional indebtedness;


•	make investments and loans;


•	enter into mergers;


•	make or declare dividends;


•	enter into commodity hedges exceeding a specified percentage of its expected production;


•	enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness;


•	incur liens;


•	sell assets; and


•	engage in transactions with affiliates.

CRP's credit agreement also requires it to maintain compliance with the following financial ratios:

•

a current ratio, which is the ratio of CRP's consolidated current assets (including unused commitments under CRP's revolving credit facility and excluding non-cash assets under Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) Topic 815, Derivatives and Hedging and certain restricted cash) to consolidated current liabilities (excluding the current portion of long-term debt under its credit agreement and non-cash liabilities under ASC 815), of not less than 1.0 to 1.0; and


•	a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP's credit agreement) to consolidated EBITDAX (as defined in CRP's credit agreement) for the rolling four fiscal quarter period ending on such day, of not greater than 4.0 to 1.0.

As of September 30, 2016, CRP was in compliance with such covenants and the financial ratios described above.

Off-Balance Sheet Arrangements

As of September 30, 2016, CRP had no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The discussion and analysis of CRP's financial condition and results of operations are based upon its condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The preparation of CRP's financial statements requires CRP to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

CRP's oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, CRP capitalizes lease acquisition costs, all development costs and successful exploration costs.

Proved Oil and Natural Gas Properties. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil, natural gas and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells and service wells, including unsuccessful development wells, are capitalized.

Unproved Properties. Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Costs. Exploration costs, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures, other geological and geophysical costs, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

Impairment of Oil and Natural Gas Properties

CRP's proved oil and natural gas properties are recorded at cost. CRP evaluates its proved properties for impairment when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. CRP estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, CRP will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future operating and capital expenditures, and discount rates.

Unproved properties costs consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. CRP evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.

Oil and Natural Gas Reserve Quantities

CRP's estimated proved reserve quantities and future net cash flows are critical to the understanding of the value of its business. They are used in comparative financial ratios and are the basis for significant accounting estimates in CRP's financial statements, including the calculations of depletion and impairment of proved oil and natural gas properties. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure calculations require a 10 percent discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, CRP makes a considerable effort in estimating its reserves. CRP engages Netherland, Sewell & Associates, Inc., CRP's independent petroleum engineer, to prepare its total calculated proved reserve PV-10. CRP expects proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. CRP evaluates and estimates its proved reserves each year-end. For purposes of depletion and impairment, reserve quantities are adjusted in accordance with U.S. GAAP for the impact of additions and dispositions.

Revenue Recognition

CRP's revenue recognition policy is significant because revenue is a key component of its results of operations and its forward-looking statements contained in the above analysis of liquidity and capital resources. CRP derives its revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when CRP's production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month, CRP makes estimates of the amount of production delivered to the purchaser and the price it will receive. CRP uses its knowledge of its properties, contractual arrangements, NYMEX and local spot market prices and other factors as the basis for these estimates. Variances between CRP's estimates and the actual amounts received are recorded in the month payment is received.

Derivative Instruments

CRP utilizes commodity derivative instruments, including swaps, collars and basis swaps, to manage the price risk associated with the forecasted sale of its oil and natural gas production. CRP's derivative instruments are not designated as hedges for accounting purposes. Accordingly, changes in fair value are recognized in CRP's condensed consolidated statements of operations in the period of change. Gains and losses on derivatives and premiums paid for put options are included in cash flows from operating activities.

Asset Retirement Obligations

CRP's asset retirement obligation represents the estimated present value of the amount CRP will incur to retire long-lived assets at the end of their productive lives, in accordance with applicable state laws. CRP's asset retirement obligation is determined by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of inception with an offsetting increase in the carrying amount of the related long-lived asset. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset.

CRP's asset retirement liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of assets and its risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity of assumptions, the costs to ultimately retire its wells may vary significantly from prior estimates.

Recently Issued Accounting Pronouncements

Please refer to Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards, to the Condensed Consolidated Financial Statements included in Exhibit 99.1 for a discussion of recent accounting pronouncements and their anticipated effect on CRP's business.

Quantitative and Qualitative Disclosures About Market Risk

CRP is exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about its potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of its market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

CRP's major market risk exposure is in the pricing that it receives for its oil, natural gas and NGLs production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and CRP expects this volatility to continue in the future. During the period from January 1, 2014 through November 1, 2016, the WTI spot price has declined from a high of $107.62 per Bbl on July 23, 2014 to $26.21 per Bbl on February 11, 2016. NGL prices generally correlate to the price of oil, and accordingly prices for these products have likewise declined and are likely to continue following that market. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and thus far in 2016. During the period from January 1, 2014 through November 1, 2016, natural gas prices have declined from a high of $7.92 per MMBtu on March 4, 2014to a low of $1.49 per MMBtu on March 4, 2016.

A $1.00 per barrel change in CRP's realized oil price would have resulted in a $1.5 million change in oil revenues for the first nine months of 2016. A $0.10 per Mcf change in CRP's realized natural gas price would have resulted in a $0.3 million change in natural gas revenues for the first nine months of 2016. A $1.00 per barrel change in CRP's realized NGL prices would have resulted in a $0.2 million change in NGL revenues for the first nine months of 2016. Oil sales contributed 87% of CRP's total revenues for the first nine months of 2016. Natural gas sales contributed 9% and NGL sales contributed 5% of its total revenues for the first nine months of 2016. CRP's oil, natural gas and NGL revenues do not include the effects of derivatives.

Due to this volatility, CRP has historically used, and it expects to continue to use, commodity derivative instruments, such as collars, swaps and basis swaps, to hedge price risk associated with a portion of its anticipated production. CRP's hedging instruments allow it to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for its drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit its potential gains from future increases in prices. CRP's credit agreement limits its ability to enter into commodity hedges covering greater than 80% of its reasonably anticipated projected production volume.

CRP's open positions as of September 30, 2016:



Description & Production Period	Volume (Bbl)	Weighted Average Swap Price ($/Bbl) (1)
Crude Oil Swaps:
October 2016 - December 2016	11,500	$	76.25
October 2016 - December 2016	23,000	62.42
October 2016 - December 2016	11,500	77.32
October 2016 - December 2016	23,000	65.58
October 2016 - December 2016	9,200	54.00
October 2016 - December 2016	9,200	53.23
October 2016 - December 2016	9,200	51.80
October 2016 - December 2016	32,200	52.10
October 2016 - December 2016	9,200	50.20
October 2016 - December 2016	9,200	40.87
October 2016 - December 2016	18,400	43.35
October 2016 - December 2016	27,600	42.75
January 2017 - December 2017	91,250	64.05
January 2017 - December 2017	36,500	54.65
January 2017 - December 2017	36,500	43.50
January 2017 - December 2017	36,500	44.85
January 2017 - December 2017	36,500	45.10
January 2017 - December 2017	109,500	44.80
January 2017 - December 2017	36,500	47.27
January 2017 - December 2017	36,500	49.00
January 2017 - December 2017	182,500	49.80
January 2017 - December 2017	73,000	52.35
January 2018 - December 2018	36,500	55.95
Crude Oil Basis Swaps:
August 2016 - November 2016	23,000	$	(1.65	)
August 2016 - November 2016	23,000	(1.05		)
August 2016 - November 2016	23,000	(1.40		)
August 2016 - November 2016	30,500	(0.55		)
August 2016 - November 2016	27,600	0.25
August 2016 - November 2016	18,400	(0.16		)
August 2016 - November 2016	9,200	(0.50		)
August 2016 - November 2016	9,200	(0.40		)
August 2016 - November 2016	27,600	(0.25		)
August 2016 - November 2016	46,000	(0.25		)
August 2016 - November 2016	46,000	(0.20		)
August 2016 - November 2016	18,400	(0.10		)
August 2016 - November 2016	18,400	0.10
November 2016 - November 2017	91,250	(0.20		)
November 2016 - November 2017	36,500	(0.20		)


(1)	The oil swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis derivative contracts are settled based on the month’s average daily implied Principal Components of CRP's Cost Structure.


(1)	The natural gas derivative contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas.

Counterparty and Customer Credit Risk

CRP's derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While CRP does not require counterparties to its derivative contracts to post collateral, CRP does evaluate the credit standing of such counterparties as it deems appropriate. The counterparties to CRP's derivative contracts currently in place have investment grade ratings.

CRP's principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of its oil and natural gas production due to the concentration of its oil and natural gas receivables with several significant customers. The inability or failure of CRP's significant customers to meet their obligations to CRP or their insolvency or liquidation may adversely affect its financial results. However, CRP believes the credit quality of its customers is high.

Joint operations receivables arise from billings to entities that own partial interests in the wells CRP operate. These entities participate in CRP's wells primarily based on their ownership in leases on which it intends to drill. CRP has little ability to control whether these entities will participate its its wells.

Interest Rate Risk

At September 30, 2016, CRP had $189.0 million of debt outstanding, with an assumed weighted average interest rate of 3.81%. Interest is calculated under the terms of CRP's credit agreement based on a LIBOR spread. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $1.9 million per year. CRP does not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to its outstanding indebtedness.

Legal Proceedings

CRP is party to lawsuits arising in the ordinary course of its business. CRP cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on CRP’s financial condition.

Due to the nature of its business, CRP is, from time to time, involved in other routine litigation or subject to disputes or claims related to its business activities, including workers’ compensation claims and employment related disputes. In the opinion of CRP’s management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on its financial condition, cash flows or results of operations.

Risk Factors

The risk factors related to CRP’s business and operations are described in the Registration Statement in the section entitled “Risk Factors” beginning on page 8, which is incorporated by reference herein, and there have been no material changes to such risk factors.

Item 9.01. Financial Statements and Exhibits.

(a) Financial Statements of Businesses Acquired

The unaudited condensed consolidated financial statements of Centennial Resource Production, LLC as of September 30, 2016 and for the three and nine months ended September 30, 2016 are included as Exhibit 99.1 to this Amendment and are incorporated by reference herein.

(b) Pro Forma Financial Information

The unaudited pro forma condensed consolidated combined statements of operations for the nine months ended September 30, 2016 and for the year ended December 31, 2015 combine the historical consolidated statements of operations of Silver Run and the historical consolidated statements of operations of CRP, giving effect to the Transactions (as defined in Exhibit 99.2) as if they had been consummated on January 1, 2015, the beginning of the earliest period presented. The unaudited pro forma condensed consolidated combined balance sheet as of September 30, 2016 combines the historical consolidated balance sheet of Silver Run and the historical condensed consolidated balance sheet of CRP, giving effect to the Transactions as if they had been consummated on September 30, 2016.

The unaudited pro forma condensed consolidated combined financial statements are included as Exhibit 99.2 to this Amendment and are incorporated by reference herein.

(d) Exhibits



Exhibit No.	Description
99.1	Unaudited condensed consolidated financial statements of Centennial Resource Production, LLC as of September 30, 2016 and for the three and nine months ended September 30, 2016.
99.2	Unaudited pro forma condensed consolidated combined financial information for Silver Run for the nine months ended September 30, 2016 and for the year ended December 31, 2015 and the unaudited pro forma condensed consolidated combined balance sheet as of September 30, 2016.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



	CENTENNIAL RESOURCE DEVELOPMENT, INC
Date: November 10, 2016
	By:	/s/ GEORGE S. GLYPHIS
	Name:	George S. Glyphis
	Title:	Chief Financial Officer, Treasurer and Assistant Secretary

EXHIBIT INDEX



Exhibit No.	Description
99.1	Unaudited condensed consolidated financial statements of Centennial Resource Production, LLC as of September 30, 2016 and for the three and nine months ended September 30, 2016.

99.2	Unaudited pro forma condensed consolidated combined financial information for Silver Run for the nine months ended September 30, 2016 and for the year ended December 31, 2015 and the unaudited pro forma condensed consolidated combined balance sheet as of September 30, 2016.

Description & Production Period

Volume (MMBtu)

Weighted Average Swap Price ($/MMbtu) (1)

Natural Gas Swaps:

January 2017 - December 2017