Oasis Petroleum Inc. - FORM 8-K - EX-99.1 - EXHIBIT

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8-K - 8-K - Oasis Petroleum Inc.	oas-123114pressrelease.htm

Exhibit 99.1

Oasis Petroleum Inc. Announces Quarter and Year Ending December 31, 2014 Earnings and Provides an Operational Update and its 2015 Outlook

Houston, Texas — February 25, 2015 — Oasis Petroleum Inc. (NYSE: OAS) (“Oasis” or the “Company”) today announced financial and operational results for the quarter and year ended December 31, 2014 and provided its 2015 outlook.

2014 Highlights


•	Increased average daily production 35% year-over-year to 45,656 barrels of oil equivalent per day (“Boepd”) in 2014, up from 33,904 Boepd in 2013. Fourth quarter 2014 average daily production of 50,143 Boepd exceeded guidance range of 47,000 to 49,000 Boepd.


•	Completed and placed on production 195 gross (147.4 net) operated wells during 2014, including 48 gross (33.6 net) operated wells in the fourth quarter of 2014. Waiting on completion backlog included 72 gross operated wells as of December 31, 2014.


•	Increased total estimated net proved oil and natural gas reserves by 24% to 272.1 million barrels of oil equivalent (“MMBoe”) at December 31, 2014, compared to year-end 2013 total estimated net proved reserves, excluding the sale of certain non-operated properties in and around the Company’s Sanish project area (“Sanish Sale”).


•	Grew Adjusted EBITDA by 16% to $952.8 million in 2014, up from $821.9 million in the prior year. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.


•	Increased net income by 122% from $228.0 million in 2013 to $506.9 million in 2014, which included a $187.0 million gain on the Sanish Sale.


•	Ended the year with $45.8 million of cash and cash equivalents and had total liquidity of $1,040.6 million, including the unused borrowing base committed capacity available under the Company’s revolving credit facility.

“Capitalizing on our premier position in the Williston Basin, we have grown volumes by over 35% in 2014, including production in the fourth quarter of 2014 of 50,143 Boepd,” said Thomas B. Nusz, Oasis’ Chairman and Chief Executive Officer. “While we are excited about the strong growth and the potential of our significant inventory position, we have turned our attention to managing the business in light of the current challenging market environment. Due to lower commodity prices, we are rolling out a capital plan for 2015 totaling $705 million, which is 12% lower than the plan we rolled out in early December 2014. Throughout the year, more and more of our capital will be focused in Indian Hills and South Cottonwood, which include our most highly productive inventory and represent over eight years of activity at our current completion pace. We also see the opportunity to further improve returns through enhanced completions, which we expect to represent approximately 60% of our program in 2015.”

Expectations for 2015

Highlights for 2015 include:


•	$705 million total capital expenditure (“CapEx”) budget, with approximately 80% allocated for drilling and completion (“D&C”) CapEx.


•	Targeting average daily production to range between 45,000 to 49,000 Boepd, representing an approximate 3% increase at the midpoint of 2015 over 2014 average daily production.


•	Completing 79 gross (63.3 net) operated and 2.6 net non-operated wells.

The Company is exploring financing opportunities for Oasis Midstream Services (“OMS”). OMS assets have historically included primarily salt water disposal (“SWD”) pipelines and wells. In 2015, the OMS CapEx budget totals $81.0 million for SWD projects on its legacy acreage and for the initial investment into a new SWD, crude oil gathering, and gas gathering and processing system in the Company’s Wild Basin project area, which is the eastern acreage block of Indian Hills that Oasis acquired in 2013. OMS produced $7.9 million of Adjusted EBITDA in the fourth quarter of 2014, and the Company expects to continue to grow this business in 2015. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to income before income taxes, see "Non-GAAP Financial Measures—Segment Adjusted EBITDA Reconciliations—Midstream Services" below.

Fiscal Year 2014 and Fourth Quarter 2014 Results

The Company’s average daily production by project area is listed in the following table:



	Quarter Ended:				Year Ended:
	12/31/2014		9/30/2014		12/31/2014		12/31/2013
Average daily production (Boepd)
West Williston	32,416		31,429		30,627		21,170
East Nesson	17,727		14,444		14,641		10,054
Sanish⁽¹⁾	—		—		388		2,680
Total	50,143		45,873		45,656		33,904
Percent Oil	89	%	89	%	89	%	90	%


(1)	Includes production from certain non-operated properties in the Company’s Sanish project area and other non-operated leases adjacent to its Sanish position until the properties were sold in March 2014.

The Company’s revenues are detailed in the following table:



	Quarter Ended:				Year Ended:
	12/31/2014		9/30/2014		12/31/2014		12/31/2013
Revenues ($ in thousands)
Oil	$	258,913	$	328,548	$	1,231,251	$	1,028,089
Bulk oil sale	—		—		—		5,777
Natural gas	14,356		16,158		72,753		50,546
Well services (OWS)	22,980		20,925		74,610		51,845
Midstream (OMS)	3,423		3,028		11,614		5,742
Total revenues	$	299,672	$	368,659	$	1,390,228	$	1,141,999

Total revenues for the fourth quarter of 2014 decreased by 19% compared to the third quarter of 2014, primarily due to lower oil and natural gas prices, offset by an increase in production as a result of the Company’s well completions in the fourth quarter of 2014. In the fourth quarter of 2014, as NYMEX West Texas Intermediate (“WTI”) crude oil prices declined, the Company’s price differentials increased as a percentage of WTI but remained relatively flat in terms of the dollar per barrel discount to WTI in the range of $9.00 to $10.50 per barrel of oil, averaging $9.74 during the fourth quarter of 2014.

The Company’s operating expenses are detailed in the following table:



	Quarter Ended:				Year Ended:
	12/31/2014		9/30/2014		12/31/2014		12/31/2013
Operating expenses ($ in thousands):
Lease operating expenses	$	44,697	$	44,361	$	169,600	$	94,634
Well services (OWS)	14,474		13,572		45,605		29,259
Midstream (OMS)	1,167		1,350		4,647		1,454
Marketing, transportation and gathering expenses⁽¹⁾	6,843		7,048		26,819		18,777
Bulk oil purchase	—		—		—		5,776
Non-cash valuation charges	2,684		258		2,314		1,371
Select operating expenses	$	69,865	$	66,589	$	248,985	$	151,271
Operating expenses ($ per Boe):
Lease operating expenses	$	9.69	$	10.51	$	10.18	$	7.65
Marketing, transportation and gathering expenses⁽¹⁾	1.48		1.67		1.61		1.52


(1)	Excludes bulk oil purchase and non-cash valuation charges.

The sequential quarter-over-quarter decrease in lease operating expenses (“LOE”) per barrel of oil equivalent (“Boe”) was primarily due to higher oil and natural gas volumes produced as well as more salt water disposal volumes going to OMS disposal wells, partially offset by increased workover costs, which include certain costs to protect producing wells from wells that are being completed, and higher LOE on non-operated volumes in the fourth quarter of 2014.

Marketing, transportation and gathering expenses, excluding non-cash valuation charges, totaled $6.8 million in the fourth quarter of 2014. The 11% sequential quarter-over-quarter decrease per Boe was primarily related to a decrease in the gathering fee on certain oil volumes due to reaching a contractual volume threshold on the gathering system, partially offset by higher operated volumes flowing through third-party oil gathering pipelines in the fourth quarter of 2014. Currently, the Company is flowing 75% of its gross operated oil production through these gathering systems. While transporting volumes through third-party oil gathering pipelines increases marketing, transportation and gathering expenses, it improves oil price realizations by reducing transportation costs included in the Company’s oil price differential for sales at the wellhead.

Production taxes for the fourth quarter of 2014 totaled $26.8 million, or 9.8% of oil and gas revenues, compared to 10.0% of oil and gas revenues for the third quarter of 2014.

Depreciation, depletion and amortization expenses (“DD&A”) totaled $116.8 million in the fourth quarter of 2014 and $107.0 million in the third quarter of 2014. DD&A was $25.32 per Boe in the fourth quarter of 2014 and $25.35 per Boe in the third quarter of 2014.

Due to lower expected future oil prices, the Company reviewed its proved oil and natural gas properties as of December 31, 2014 and determined that the carrying value exceeded the expected undiscounted cash flows for certain legacy wells that have been producing from conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken and Three Forks (“TFS”) formations. As a result, the Company recorded an impairment loss of $40.0 million in the fourth quarter of 2014 to adjust the carrying amount of these assets to fair value. No impairment of proved oil and natural gas properties was recorded during 2013. During the fourth quarters of 2014 and 2013, the Company recorded non-cash impairment charges of $5.0 million and $0.4 million, respectively, for unproved properties due to leases that expired during the period and periodic assessments of unproved properties not held-by-production. The impairment charge in the fourth quarter of 2014 included $2.9 million related to acreage expiring in 2015 and 2016 as a result of a periodic assessment because there were no plans to drill or extend these leases prior to their expiration. In 2013, the Company did not record any impairment charges as a result of periodic assessments based on its ability to actively manage and prioritize its CapEx to drill leases and to make payments to extend leases that would otherwise expire.

General and administrative (“G&A”) expenses for the fourth quarter of 2014 totaled $24.1 million compared to $23.9 million in the third quarter of 2014. G&A expenses were $5.23 per Boe in the fourth quarter of 2014 and $5.67 per Boe in the third quarter of 2014.

As a result of its derivative activities and forward oil price changes, the Company incurred a $306.8 million net gain on derivative instruments, including net cash settlement receipts from derivatives, which are settled at the beginning of the month following the contract period, of $31.5 million, for the fourth quarter of 2014 and a $103.4 million net gain on derivative instruments, including net cash settlement payments of $11.1 million, for the third quarter of 2014. The Company’s derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes.

Interest expense was $39.8 million for the fourth quarter of 2014 compared to $39.4 million for the third quarter of 2014. The $0.4 million increase from the third quarter of 2014 was primarily due to higher weighted average borrowings under the Company’s revolving credit facility, partially offset by an increase in interest capitalized in the fourth quarter of 2014. Capitalized interest totaled $2.7 million for the fourth quarter of 2014 and $2.3 million for the third quarter of 2014.

Income tax expense was $106.3 million for the three months ended December 31, 2014, resulting in an effective tax rate of 37.6%. The Company’s income tax expense for the three months ended September 30, 2014 was recorded at 38.6% of pre-tax net income. The Company’s effective tax rate is expected to continue to closely approximate the statutory rate applicable to the U.S. and the blended rate for each of the states in which the Company conducts business.

Adjusted EBITDA for the fourth quarter of 2014 was $219.5 million, a decrease of $19.3 million, or 8%, compared to the third quarter of 2014 of $238.8 million. Adjusted EBITDA for the full year 2014 was $952.8 million, an increase of $130.9 million, or 16%, over the full year 2013 of $821.9 million.

The Company reported net income of $176.5 million in the fourth quarter of 2014 compared to $121.6 million in the third quarter of 2014. For the full year 2014, Oasis reported net income of $506.9 million compared to $228.0 million for the full year 2013. Excluding certain non-cash items and their tax effect in the fourth and third quarters of 2014, Adjusted Net Income (non-GAAP) was $35.1 million, or $0.35 per diluted share, and $52.3 million, or $0.52 per diluted share, respectively. Excluding certain non-cash items and their tax effect for the years ending December 31, 2014 and 2013, Adjusted Net Income (non-GAAP) was $222.6 million, or $2.22 per diluted share, and $247.0 million, or $2.64 per diluted share, respectively. For a definition of Adjusted Net Income and a reconciliation of net income to Adjusted Net Income, see “Non-GAAP Financial Measures” below.

Capital Expenditures

The following table depicts the Company’s exploration and production (“E&P”) CapEx by project area and total CapEx for the periods presented:



	2014
	1Q		2Q		3Q		4Q		FY
CapEx ($ in thousands)
E&P CapEx by Project Area
West Williston	$	189,288	$	223,526	$	244,933	$	312,822	$	970,569
East Nesson	107,843		103,370		174,644		149,435		535,292
Total E&P CapEx⁽¹⁾	$	297,131	$	326,896	$	419,577	$	462,257	$	1,505,861
OWS	6,410		18,903		9,070		2,909		37,292
Other Non-E&P⁽²⁾	3,957		6,036		8,921		10,526		29,440
Total Company CapEx⁽³⁾	$	307,498	$	351,835	$	437,568	$	475,692	$	1,572,593


(1)	Total E&P CapEx includes $68.9 million for OMS and a reduction to capital related to Oasis Well Services (“OWS”) of $56.6 million for the full year 2014.


(2)	Other non-E&P CapEx includes such items as administrative capital and capitalized interest.


(3)	CapEx reflected in the table above differs from the amounts shown in the statement of cash flows in the Company’s condensed consolidated financial statements because amounts reflected in the table above include accrued liabilities for CapEx, while the amounts presented in the statement of cash flows are presented on a cash basis.

Liquidity

As of December 31, 2014, Oasis had liquidity of $1,040.6 million, including cash and cash equivalents of $45.8 million, and $500.0 million of borrowings and $5.2 million of outstanding letters of credit issued under its revolving credit facility, resulting in an unused borrowing base committed capacity of $994.8 million. On September 30, 2014, Oasis increased its borrowing base from $1,750.0 million to $2,000.0 million. However, the Company elected to limit the lenders’ aggregate commitment to $1,500.0 million.

Operational Results for Bakken and TFS

The following table describes the Company’s producing Bakken and TFS wells by project area in the Williston Basin as of December 31, 2014:



	Bakken/Three Forks Producing Wells
	West Williston		East Nesson		Total Williston Basin
	Gross	Net	Gross	Net	Gross	Net
Production started in 2014:
Operated	121	87.1	74	60.3	195	147.4
Non-Operated	47	2.7	27	1.0	74	3.7
Production started in Q4 2014:
Operated	43	28.9	5	4.7	48	33.6
Non-Operated	11	0.6	21	0.8	32	1.4
Total Producing Wells on 12/31/2014:
Operated	431	327.5	220	177.1	651	504.6
Non-Operated	198	15.2	124	8.0	322	23.2

As of December 31, 2014, the Company had 72 gross operated wells awaiting completion.

Leasehold Position and Drilling Locations

As of December 31, 2014, Oasis had 505,503 net acres in the Williston Basin, including 433,794 net acres held-by-production.

As a result of prior downspacing and delineation tests across its acreage position, extensive subsurface modeling, project evaluation, and adjustments for 2014 well completions, Oasis has refined its inventory assumptions. The Company eliminated certain uneconomic lower bench TFS wells and certain TFS wells in North Cottonwood, South Cottonwood, and Foreman

Butte that were previously included in its inventory. Oasis now assumes approximately seven wells per drilling spacing unit (“DSU”) across its 216 DSUs in Montana, Foreman Butte, and North Cottonwood. Oasis now includes 72 DSUs in Indian Hills and South Cottonwood, and continues to expect to drill approximately 15 wells per DSU in these areas. In Indian Hills and South Cottonwood, the Company counts 825 remaining operated drilling locations, of which 701 locations are targeting the Bakken and the first bench of the TFS. Across the Company’s 405 operated DSUs, Oasis believes that its remaining inventory includes 3,046 gross (2,069 net) operated drilling locations as of December 31, 2014.

Estimated Net Proved Reserves

Oasis’ estimated net proved oil and natural gas reserves at December 31, 2014 were 272.1 MMBoe, a 19% increase over year-end 2013 estimated net proved reserves, and consisted of 235.4 barrels (“MMBbls”) of oil and 220.1 billion cubic feet (“Bcf”) of natural gas utilizing a 12-month index average price of $95.28 per barrel for oil and $4.35 per MMBtu for gas. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. At year-end 2014, 87% of the Company’s total estimated net proved reserves were from oil.

The table below summarizes the Company’s estimated net proved reserves and related PV-10 at December 31, 2014 and 2013 for each project area based on reports prepared by DeGolyer and MacNaughton, independent reserve engineers. In preparing its reports, DeGolyer and MacNaughton evaluated properties representing all of the Company’s PV-10 at December 31, 2014 and 2013 in accordance with rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in oil and natural gas producing activities. The information in the following table does not give any effect to or reflect Oasis’ commodity hedges.



	At December 31, 2014			At December 31, 2013
Project area	Proved reserves (MMBoe)	PV-10⁽¹⁾ (in millions)		Proved reserves (MMBoe)	PV-10⁽¹⁾ (in millions)
West Williston	197.8	$	3,927.4	154.0	$	3,571.0
East Nesson	74.3	1,554.0		65.3	1,663.4
Sanish	—	—		8.6	252.5
Total Williston Basin	272.1	$	5,481.4	227.9	$	5,486.9

(1)

PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. Our estimated net proved reserves and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $95.28/Bbl for oil and $4.35/MMBtu for natural gas and $96.96/Bbl for oil and $3.66/MMBtu for natural gas for the years ended December 31, 2014 and 2013, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end.

Estimated net proved developed reserves increased from 122.1 MMBoe at year-end 2013 to 146.3 MMBoe at year-end 2014. The PV-10 of the Company’s estimated net proved developed reserves increased to $4,113 million at year-end 2014 from $3,706 million at year-end 2013.

At December 31, 2014, Oasis had approximately 125.7 MMBoe of estimated proved undeveloped reserves as compared to 105.8 MMBoe at December 31, 2013, primarily due to its 2014 drilling program and changes to align its proved undeveloped reserves with its anticipated five-year drilling plan. The Company expects to develop all of its proved undeveloped reserves as of December 31, 2014 within five years of their initial booking.

The following table summarizes the changes in Oasis’ estimated net proved reserves during 2014:



	MBoe
Estimated net proved reserves
Beginning balance at December 31, 2013	227.9
Revisions of previous estimates	(25.1	)
Extensions, discoveries and other additions	92.6
Sales of reserves in place	(8.4	)
Purchases of reserves in place	1.8
Production	(16.7	)
Net proved reserves at December 31, 2014	272.1
% Proved developed	53.8	%

2015 Plan

The Company’s 2015 CapEx budget totals $705 million, which consists of $678 million for E&P CapEx and $27 million for non-E&P CapEx. The planned E&P CapEx includes $565 million of drilling and completion CapEx for operated and non-operated wells (including production-related equipment and expected savings from services provided by OWS and OMS) and $81 million for OMS. Non-E&P CapEx includes OWS capital for additional horsepower for high intensity completions and such items as administrative capital and capitalized interest.

The Company expects to complete 79 gross (63.3 net) operated wells and 2.6 net non-operated wells in 2015.

The following table provides Oasis’ forward-looking guidance for 2015:



	2015 Range
Metric
Production (Boepd)
Full Year 2015	45,000 - 49,000
1Q15	47,000 - 49,000
Full Year Financial Metrics
LOE ($/BOE)	$9.50 - $10.50
Marketing, transportation and gathering ($/BOE)⁽¹⁾	$1.50 - $1.80
G&A ($ in millions)⁽²⁾	$95 - $100
Production taxes (% of oil and gas revenue)	9.0% - 10.0%


(1)	Excludes the effect of non-cash valuation charges.


(2)	Includes non-cash amortization of restricted stock of $27-$29 million.

Hedging Activity

As of February 25, 2015, the Company had the following outstanding commodity derivate contracts, all of which are priced off of WTI crude oil index prices and settle monthly:



		Weighted Average Prices ($/Bbl)							Total
Current Hedged Volumes	Term	Floor		Ceiling		Swaps		BOPD	Barrels
2015
Full Year
Swaps	January - December					$	90.15	10,000	3,650,000
Two-way collars	January - December	$	86.00	$	103.42			5,000	1,825,000
First Half
Swaps	January - June					$	91.26	9,000	1,629,000
Deferred premium puts⁽¹⁾	January - June	$	87.45					6,000	1,086,000
Two-way collars	January - June	$	90.00	$	99.10			2,000	362,000
Partial Year
Swaps	October - December					$	60.87	2,000	184,000
Total 2015 hedges (weighted average)		$	86.92	$	102.70	$	89.49	23,934	8,736,000
Total 1H15 Hedges								32,000
Total 2H15 Hedges								16,000


(1)	Floor price is net of deferred premium of $2.55.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company’s drilling program, production, derivatives activities, capital expenditure levels and other guidance included in this press release. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as the Company’s ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

About Oasis Petroleum Inc.

Oasis is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources, primarily operating in the Williston Basin. For more information, please visit the Company’s website at www.oasispetroleum.com.

Oasis Petroleum Inc. Financial Statements

OASIS PETROLEUM INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)



	December 31,
	2014			2013
	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	45,811		$	91,901
Accounts receivable — oil and gas revenues	130,934			175,653
Accounts receivable — joint interest partners	175,537			139,459
Inventory	21,354			20,652
Prepaid expenses	14,273			10,191
Deferred income taxes	—			6,335
Derivative instruments	302,159			2,264
Advances to joint interest partners	13			760
Other current assets	6,526			391
Total current assets	696,607			447,606
Property, plant and equipment
Oil and gas properties (successful efforts method)	5,966,140			4,528,958
Other property and equipment	313,439			188,468
Less: accumulated depreciation, depletion, amortization and impairment	(1,092,793		)	(637,676		)
Total property, plant and equipment, net	5,186,786			4,079,750
Assets held for sale	—			137,066
Derivative instruments	13,348			1,333
Deferred costs and other assets	41,671			46,169
Total assets	$	5,938,412		$	4,711,924
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	20,958		$	8,920
Revenues and production taxes payable	209,890			146,741
Accrued liabilities	410,379			241,830
Accrued interest payable	49,786			47,910
Derivative instruments	—			8,188
Deferred income taxes	97,499			—
Advances from joint interest partners	6,616			12,829
Total current liabilities	795,128			466,418
Long-term debt	2,700,000			2,535,570
Deferred income taxes	526,770			323,147
Asset retirement obligations	42,097			35,918
Derivative instruments	—			139
Other liabilities	2,116			2,183
Total liabilities	4,066,111			3,363,375
Commitments and contingencies
Stockholders’ equity
Common stock, $0.01 par value: 300,000,000 shares authorized; 101,627,296 shares and 100,866,589 shares issued at December 31, 2014 and 2013, respectively	1,001			996
Treasury stock, at cost: 285,677 shares and 167,155 shares at December 31, 2014 and 2013, respectively	(10,671		)	(5,362		)
Additional paid-in-capital	1,007,202			985,023
Retained earnings	874,769			367,892
Total stockholders’ equity	1,872,301			1,348,549
Total liabilities and stockholders’ equity	$	5,938,412		$	4,711,924

OASIS PETROLEUM INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)



	Three Months Ended December 31,						Year Ended December 31,
	2014			2013			2014			2013
	(In thousands, except per share data)
Revenues
Oil and gas revenues	$	273,269		$	313,967		$	1,304,004		$	1,084,412
Well services and midstream revenues	26,403			19,648			86,224			57,587
Total revenues	299,672			333,615			1,390,228			1,141,999
Expenses
Lease operating expenses	44,697			35,048			169,600			94,634
Well services and midstream operating expenses	15,641			10,836			50,252			30,713
Marketing, transportation and gathering expenses	9,527			6,068			29,133			25,924
Production taxes	26,768			30,228			127,648			100,537
Depreciation, depletion and amortization	116,814			101,276			412,334			307,055
Exploration expenses	1,109			(452		)	3,064			2,260
Impairment of oil and gas properties	44,995			406			47,238			1,168
General and administrative expenses	24,120			28,072			92,306			75,310
Total expenses	283,671			211,482			931,575			637,601
Gain on sale of properties	(77		)	—			186,999			—
Operating income	15,924			122,133			645,652			504,398
Other income (expense)
Net gain (loss) on derivative instruments	306,758			6,406			327,011			(35,432		)
Interest expense, net of capitalized interest	(39,822		)	(41,736		)	(158,390		)	(107,165		)
Other income (expense)	(55		)	119			195			1,216
Total other income (expense)	266,881			(35,211		)	168,816			(141,381		)
Income before income taxes	282,805			86,922			814,468			363,017
Income tax expense	106,301			32,432			307,591			135,058
Net income	$	176,504		$	54,490		$	506,877		$	227,959
Earnings per share:
Basic	$	1.77		$	0.58		$	5.09		$	2.45
Diluted	1.77			0.57			5.05			2.44
Weighted average shares outstanding:
Basic	99,767			94,228			99,677			92,867
Diluted	99,767			94,821			100,365			93,411

OASIS PETROLEUM INC.

SELECTED FINANCIAL AND OPERATIONAL STATS



	Three Months Ended December 31,				Year Ended December 31,
	2014		2013		2014		2013
Operating results ($ in thousands):
Revenues
Oil	$	258,913	$	295,903	$	1,231,251	$	1,033,866
Natural gas	14,356		18,064		72,753		50,546
Well services and midstream	26,403		19,648		86,224		57,587
Total revenues	$	299,672	$	333,615	$	1,390,228	$	1,141,999
Production data:
Oil (MBbls)	4,123		3,446		14,883		11,133
Natural gas (MMcf)	2,939		2,567		10,691		7,450
Oil equivalents (MBoe)	4,613		3,874		16,664		12,375
Average daily production (Boe/d)	50,143		42,106		45,656		33,904
Average sales prices:
Oil, without derivative settlements (per Bbl)⁽¹⁾	$	62.79	$	85.87	$	82.73	$	92.34
Oil, with derivative settlements (per Bbl)⁽¹⁾⁽²⁾	70.44		85.00		83.19		91.61
Natural gas (per Mcf)⁽³⁾	4.89		7.04		6.81		6.78
Costs and expenses (per Boe of production):
Lease operating expenses	$	9.69	$	9.05	$	10.18	$	7.65
Marketing, transportation and gathering expenses⁽⁴⁾	1.48		1.36		1.61		1.52
Production taxes	5.80		7.80		7.66		8.12
Depreciation, depletion and amortization	25.32		26.14		24.74		24.81
General and administrative expenses	5.23		7.25		5.54		6.09


(1)	For the year ended December 31, 2013, the average sales price for oil is calculated using total oil revenues, excluding bulk oil sales of $5.8 million, divided by oil production.

(2)

Realized prices include gains or losses on cash settlements for commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.


(3)	Natural gas prices include the value for natural gas and natural gas liquids.


(4)	Excludes bulk oil purchase and non-cash valuation charges.

OASIS PETROLEUM INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)



	Year Ended December 31,
	2014			2013
	(In thousands)
Cash flows from operating activities:
Net income	$	506,877		$	227,959
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	412,334			307,055
Gain on sale of properties	(186,999		)	—
Impairment of oil and gas properties	47,238			1,168
Deferred income taxes	307,457			134,583
Derivative instruments	(327,011		)	35,432
Stock-based compensation expenses	21,302			11,982
Deferred financing costs amortization and other	11,028			4,248
Working capital and other changes:
Change in accounts receivable	16,702			(107,473		)
Change in inventory	(3,776		)	(13,941		)
Change in prepaid expenses	(3,199		)	(8,191		)
Change in other current assets	(6,135		)	(56		)
Change in other assets	114			(3,248		)
Change in accounts payable and accrued liabilities	76,723			107,451
Change in other liabilities	(139		)	887
Net cash provided by operating activities	872,516			697,856
Cash flows from investing activities:
Capital expenditures	(1,354,281		)	(893,524		)
Acquisition of oil and gas properties	(46,247		)	(1,560,072		)
Proceeds from sale of properties	324,852			—
Costs related to sale of properties	(2,337		)	—
Derivative settlements	6,774			(8,133		)
Redemptions of short-term investments	—			25,000
Advances from joint interest partners	(6,213		)	(8,347		)
Net cash used in investing activities	(1,077,452		)	(2,445,076		)
Cash flows from financing activities:
Proceeds from issuance of senior notes	—			1,000,000
Proceeds from revolving credit facility	620,000			600,000
Principal payments on revolving credit facility	(455,570		)	(264,430		)
Debt issuance costs	(99		)	(22,910		)
Proceeds from sale of common stock	—			314,580
Purchases of treasury stock	(5,309		)	(1,566		)
Other	(176		)	—
Net cash provided by financing activities	158,846			1,625,674
Decrease in cash and cash equivalents	(46,090		)	(121,546		)
Cash and cash equivalents:
Beginning of period	91,901			213,447
End of period	$	45,811		$	91,901
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	150,181		$	85,596
Cash paid for taxes	5,329			750
Supplemental non-cash transactions:
Change in accrued capital expenditures	$	169,710		$	34,354
Change in asset retirement obligations	6,182			13,201

Non-GAAP Financial Measures

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion, amortization, exploration expenses and other similar non-cash or non-recurring charges. Adjusted EBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.

The following table presents reconciliations of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA for the periods presented:

Adjusted EBITDA Reconciliations



	Three Months Ended December 31,						Year Ended December 31,
	2014			2013			2014			2013
	(In thousands)
Net income	$	176,504		$	54,490		$	506,877		$	227,959
Loss (gain) on sale of properties	77			—			(186,999		)	—
Net (gain) loss on derivative instruments	(306,758		)	(6,406		)	(327,011		)	35,432
Derivative settlements⁽¹⁾	31,547			(2,998		)	6,774			(8,133		)
Interest expense, net of capitalized interest	39,822			41,736			158,390			107,165
Depreciation, depletion and amortization	116,814			101,276			412,334			307,055
Impairment of oil and gas properties	44,995			406			47,238			1,168
Exploration expenses	1,109			(452		)	3,064			2,260
Stock-based compensation expenses	5,547			3,571			21,302			11,982
Income tax expense	106,301			32,432			307,591			135,058
Other non-cash adjustments	3,561			1,321			3,284			1,910
Adjusted EBITDA	$	219,519		$	225,376		$	952,844		$	821,856

Net cash provided by operating activities	$	199,024		$	161,175		$	872,516		$	697,856
Derivative settlements⁽¹⁾	31,547			(2,998		)	6,774			(8,133		)
Interest expense, net of capitalized interest	39,822			41,736			158,390			107,165
Exploration expenses	1,109			(452		)	3,064			2,260
Deferred financing costs amortization and other	(5,819		)	(1,555		)	(11,028		)	(4,248		)
Current tax expense	(3,608		)	93			134			475
Changes in working capital	(46,117		)	26,056			(80,290		)	24,571
Other non-cash adjustments	3,561			1,321			3,284			1,910
Adjusted EBITDA	$	219,519		$	225,376		$	952,844		$	821,856


(1)	Cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

The following tables present reconciliations of the GAAP financial measure of income before income taxes to the non-GAAP financial measure of Adjusted EBITDA for the Company’s three reportable business segments for the periods presented:

Segment Adjusted EBITDA Reconciliations



	Exploration and Production
	Three Months Ended December 31,						Year Ended December 31,
	2014			2013			2014			2013
	(In thousands)
Income before income taxes	$	274,934		$	78,819		$	779,591		$	331,781
Loss (gain) on sale of properties	77			—			(186,999		)	—
Net (gain) loss on derivative instruments	(306,758		)	(6,406		)	(327,011		)	35,432
Derivative settlements⁽¹⁾	31,547			(2,998		)	6,774			(8,133		)
Interest expense, net of capitalized interest	39,822			41,736			158,390			107,165
Depreciation, depletion and amortization	114,705			100,180			406,960			304,388
Impairment of oil and gas properties	44,995			406			47,238			1,168
Exploration expenses	1,109			(452		)	3,064			2,260
Stock-based compensation expenses	5,303			3,406			20,701			11,602
Other non-cash adjustments	2,591			782			2,314			1,371
Adjusted EBITDA	$	208,325		$	215,473		$	911,022		$	787,034


(1)	Cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.



	Well Services
	Three Months Ended December 31,				Year Ended December 31,
	2014		2013		2014		2013
	(In thousands)
Income before income taxes	$	17,741	$	16,836	$	70,953	$	56,338
Depreciation, depletion and amortization	4,362		2,281		14,080		7,150
Stock-based compensation expenses	475		337		1,658		969
Other non-cash adjustments	970		539		970		539
Adjusted EBITDA	$	23,548	$	19,993	$	87,661	$	64,996



	Midstream Services
	Three Months Ended December 31,				Year Ended December 31,
	2014		2013		2014		2013
	(In thousands)
Income before income taxes	$	6,876	$	5,719	$	22,730	$	17,509
Depreciation, depletion and amortization	1,032		810		3,744		2,780
Adjusted EBITDA	$	7,908	$	6,529	$	26,474	$	20,289

Adjusted Net Income and Adjusted Diluted Earnings Per Share are supplemental non-GAAP financial measures that are used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted Net Income as net income after adjusting first for (1) the impact of certain non-cash and non-recurring items, including non-cash changes in the fair value of derivative instruments, impairment of oil and gas properties, and other similar non-cash and non-recurring charges, and then (2) the non-cash and non-recurring items’ impact on taxes based on the Company’s effective tax rate in the same period. Adjusted Net Income is not a measure of net income as determined by GAAP. The Company defines Adjusted Diluted Earnings Per Share as Adjusted Net Income divided by diluted weighted average shares outstanding.

The following table presents reconciliations of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted Net Income and the GAAP financial measure of diluted earnings per share to the non-GAAP financial measure of Adjusted Diluted Earnings Per Share for the periods presented:

Adjusted Net Income and Adjusted Diluted Earnings Per Share Reconciliations



	Three Months Ended December 31,						Year Ended December 31,
	2014			2013			2014			2013

Net income	$	176,504		$	54,490		$	506,877		$	227,959
Loss (gain) on sale of properties	77			—			(186,999		)	—
Net (gain) loss on derivative instruments	(306,758		)	(6,406		)	(327,011		)	35,432
Derivative settlements⁽¹⁾	31,547			(2,998		)	6,774			(8,133		)
Impairment of oil and gas properties	44,995			406			47,238			1,168
Other non-cash adjustments	3,561			1,321			3,284			1,910
Tax impact⁽²⁾	85,195			2,864			172,482			(11,302		)
Adjusted Net Income	$	35,121		$	49,677		$	222,645		$	247,034

Diluted earnings per share	$	1.77		$	0.57		$	5.05		$	2.44
Gain on sale of properties	—			—			(1.86		)	—
Net (gain) loss on derivative instruments	(3.07		)	(0.07		)	(3.26		)	0.38
Derivative settlements⁽¹⁾	0.32			(0.03		)	0.07			(0.09		)
Impairment of oil and gas properties	0.45			—			0.47			0.01
Other non-cash adjustments	0.04			0.01			0.03			0.02
Tax impact⁽²⁾	0.84			0.04			1.72			(0.12		)
Adjusted Diluted Earnings Per Share	$	0.35		$	0.52		$	2.22		$	2.64

Diluted weighted average shares outstanding	99,767			94,821			100,365			93,411

Effective tax rate	37.6		%	37.3		%	37.8		%	37.2		%


(1)	Cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.


(2)	The tax impact is computed utilizing the Company’s effective tax rate on the adjustments for certain non-cash and non-recurring items.

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