Edgar Filing: Matador Resources Co

MATADOR RESOURCES COMPANY

Date: September 4, 2013

/s/ Craig N. Adams

Craig N. Adams

Executive Vice President

8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (date of earliest event reported): September 3, 2013

Matador Resources Company

(Exact name of registrant as specified in its charter)


Texas	001-35410	27-4662601
(State or Other Jurisdiction of Incorporation or Organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

5400 LBJ Freeway, Suite 1500, Dallas, Texas		75240
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code: (972) 371-5200

Not Applicable

(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))

Item 7.01. Regulation FD Disclosure.

On September 3, 2013, Matador Resources Company (the “Company,” “Matador,” “we,” or “our” ) issued a press release announcing the commencement, subject to market conditions, of an underwritten public offering of 8,500,000 shares of its common stock (the “Offering”). The Company will also grant the underwriters a 30-day option to purchase up to 1,275,000 additional shares of common stock from the Company. A copy of the press release is furnished as Exhibit 99.1 to this Current Report on Form 8-K (this “Current Report”).

The information furnished pursuant to this Item 7.01, including Exhibit 99.1, shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.

Item 8.01. Other Events.

The discussion below contains certain information included in our preliminary prospectus supplement filed with the Securities and Exchange Commission (the “SEC”) on September 3, 2013:

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South Texas.

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At September 1, 2013, we had 38,900 gross (27,200 net) acres in the Eagle Ford shale play in South Texas, of which we believe approximately 87% to be prospective predominantly for oil or liquids production. At September 1, 2013, approximately 72% of our Eagle Ford acreage was held by production. We intend to operate two drilling rigs in the Eagle Ford shale for the remainder of 2013 and throughout 2014.

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At September 1, 2013, we had 54 gross (47.1 net) wells producing from the Eagle Ford shale in South Texas, and we had identified 269 gross (218.4 net) locations for potential future drilling on our Eagle Ford acreage. Of these locations, at September 1, 2013, we consider 155 gross (129.3 net) locations as Tier 1 locations. Of these Tier 1 locations, 117 gross (114.1 net) locations would be operated by us. These identified locations presume that we will be able to develop our Eagle Ford properties on 40-acre to 80-acre spacing, depending on the specific property and the wells we have already drilled. At September 1, 2013, these identified drilling locations included 25 gross (23.0 net) locations in the Eagle Ford shale to which we have assigned proved undeveloped reserves.

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Southeast New Mexico and West Texas.

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At September 1, 2013, we had 50,800 gross (32,900 net) acres in the Permian Basin in Southeast New Mexico and West Texas, of which we consider 43,100 gross (32,300 net) acres to be prospective for multiple oil and liquids-rich targets, including the Wolfcamp and Bone Spring plays, as well as other potential shallower targets (Delaware) and deeper targets (Atoka, Morrow). Between January 1, 2013 and September 1, 2013, we acquired approximately 35,000 gross (26,800 net) acres in the Permian Basin in Southeast New Mexico and West Texas, primarily in Lea and Eddy Counties, New Mexico. As a result of our recent acreage acquisitions in this area, the preliminary indications from our drilling program and the production results from nearby operators, we now expect to keep a rig operating continuously in the Permian Basin for the remainder of 2013 and throughout 2014.

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At September 1, 2013, we were testing potential completion intervals on our first test well and were drilling a horizontal lateral in the Second Bone Spring sand in our second test well. At September 1, 2013, we had identified 107 gross (74.5 net) locations for potential future drilling in the Wolfcamp or Bone Spring plays on our acreage in Southeast New Mexico and West Texas, including the two test wells already drilled or in process. At September 1, 2013, these identified drilling locations included two gross (1.2 net) locations in the Wolfcamp play to which we have assigned proved undeveloped reserves.

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Northwest Louisiana and East Texas. We had 28,500 gross (25,300 net) acres in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas at September 1, 2013, of which 22,600 gross (14,500 net) were prospective for the Haynesville shale. This acreage includes approximately 6,100 net acres in what we believe to be the core area of the Haynesville shale play. At September 1, 2013, we had identified 515 gross (102.1 net) locations for potential future drilling in the Haynesville shale, including 440 gross (51.2 net) locations within the 6,100 net acres that we believe are located in the core area of the play. At September 1, 2013, these identified drilling locations included 92 gross (12.1 net) locations in the Haynesville shale to which we have assigned proved undeveloped reserves. We have no plans to drill any operated Haynesville shale or Cotton Valley wells in 2013, but during the six months ended June 30, 2013, we participated in five gross (0.4 net) non-operated Haynesville wells, and we expect to participate in additional non-operated Haynesville wells in the second half of 2013 and in 2014. At September 1, 2013, approximately 97% of our Haynesville acreage was held by production or consisted of fee mineral interests that we owned.

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Wyoming, Utah and Idaho. In addition, we had 76,500 gross (36,000 net) acres at September 1, 2013 in Southwest Wyoming and adjacent areas of Utah and Idaho.

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Recent Production. During the months of June and July 2013, our average daily oil equivalent production increased to 12,689 BOE per day, including 6,200 Bbl of oil per day (as compared to 4,825 Bbl per day for the first five months of 2013) and 38.9 MMcf of natural gas per day (as compared to 33.8 MMcf per day for the first five months of 2013).

The following table presents certain summary data for each of our operating areas at and for the six months ended June 30, 2013, except as otherwise provided below:


	Net Acreage⁽¹⁾		Producing Wells⁽¹⁾				Total Engineered Drilling Locations⁽²⁾				Estimated Net Proved Reserves				PV-10⁽³⁾		Avg. Daily Production
			Gross		Net		Gross		Net		MBOE⁽⁴⁾		% Developed		(In millions)		(BOE/d)⁽⁴⁾⁽⁵⁾
South Texas:
Eagle Ford⁽⁶⁾		27,233		59.0		51.3		269.0		218.4		15,664		58.7	$	467.2		9,308
NW Louisiana/East Texas:
Haynesville		14,499		136.0		12.9		515.0		102.1		20,998		24.6		41.9		2,732
Cotton Valley⁽⁷⁾		22,469		106.0		69.7		71.0		49.3		1,765		100.0		10.3		630

Area Total⁽⁸⁾		25,291		242.0		82.6		586.0		151.4		22,763		30.4		52.2		3,362
Permian Basin:
SE New Mexico, West Texas⁽⁹⁾		32,899		13.0		5.8		107.0		74.5		504		18.9		2.9		19
Other:
Wyoming, Utah, Idaho		36,004		—		—		—		—		—		—		—		—

Total		121,427		314.0		139.7		962.0		444.3		38,931		41.7	$	522.3		12,689

(1)	Net acreage and producing well information is presented at September 1, 2013.

(2)

Identified and engineered drilling location information is presented at September 1, 2013. These locations have been identified for potential future drilling (other than the two test wells already drilled or in process, which are included in the drilling locations for the Permian Basin) and are not currently producing. In addition, the total net engineered drilling locations is calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At September 1, 2013, these engineered drilling locations included 25 gross (23.0 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford, 92 gross (12.1 net) locations to which we have assigned proved undeveloped reserves in the Haynesville and two gross (1.2 net) locations to which we have assigned proved undeveloped reserves in the Wolfcamp. We had no proved undeveloped reserves assigned to identified drilling locations in the Cotton Valley at September 1, 2013.

(3)

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 effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at June 30, 2013 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at June 30, 2013 were approximately $44.7 million.

(4)	Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(5)	During the months of June and July 2013.

(6)	Includes two wells producing small quantities of natural gas from the San Miguel formation, two wells producing from the Austin Chalk formation in Zavala County, Texas and one well producing from the Buda formation in Atascosa County, Texas.

(7)	Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(8)

Some of the same leases cover the net acres shown for both the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

(9)	Includes potential future drilling locations identified in either the Wolfcamp or Bone Spring plays on our acreage in Southeast New Mexico and West Texas at September 1, 2013.

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2013 Capital Program and Outlook.

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In mid-August 2013, we added a third drilling rig and returned to operating two contracted drilling rigs in the Eagle Ford shale play in South Texas. At September 1, 2013, one rig was drilling on our leasehold acreage in Karnes County, Texas, and the second rig was drilling on our leasehold acreage in La Salle County, Texas. We expect to operate two rigs in the Eagle Ford shale for the remainder of 2013 and throughout 2014. As a result of our recent acreage acquisitions in Southeast New Mexico and West Texas, the preliminary indications from our drilling program and the production results from nearby operators, we intend to operate one contracted drilling rig continuously in Southeast New Mexico and West Texas for the remainder of 2013 and throughout 2014. As a result of adding a third drilling rig, we have increased our 2013 capital expenditure budget to approximately $370.0 million, of which $168.6 million, or approximately 46%, was incurred in the first six months of 2013. Excluding any possible significant acquisitions, we expect to maintain our current financial flexibility by funding the remainder of our 2013 and our 2014 capital expenditure budget through the net proceeds we receive from the Offering, together with our cash flows and future potential borrowings under our revolving credit facility assuming anticipated increases to our borrowing base, primarily as a result of anticipated increases in our proved developed oil and natural gas reserves.

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We expect that approximately 78% of our increased 2013 capital expenditure budget will be directed to increasing our oil production and oil reserves in South Texas. We also plan to allocate approximately 20% of our increased 2013 capital expenditure budget to the exploration and acquisition of additional interests in the Wolfcamp, Bone Spring and other oil and liquids-rich plays in Southeast New Mexico and West Texas. As a result of these anticipated capital expenditures in South Texas, Southeast New Mexico and West Texas, we plan to allocate approximately 98% of our 2013 anticipated capital expenditure budget and preliminary 2014 capital expenditure budget to opportunities prospective for oil and liquids production. Our preliminary 2014 capital expenditure budget is estimated at between $425 million and $450 million, and includes approximately $400 million for drilling and completing oil and natural gas exploration and development wells with the remainder allocated to lease acquisitions, seismic data, pipelines and other infrastructure.

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Our remaining 2013 and 2014 capital expenditure budgets are subject to change depending upon a number of factors, including additional well results and other data from the Eagle Ford shale and the Wolfcamp and Bone Spring plays, results of horizontal and vertical drilling and recompletions, economic and industry conditions, prevailing and anticipated prices for oil, natural gas liquids and natural gas, the availability of sufficient capital resources for drilling prospects, potential acquisitions and our financial results.

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Credit Facility. At August, 31, 2013, the borrowing base under our revolving credit facility was $350.0 million, and we had $275.0 million in borrowings outstanding, excluding letters of credit.

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Operational and Cost Efficiencies. Between early 2011 and September 1, 2013, we have reduced average drilling and completion costs per gross well from approximately $9.9 million to approximately $6.3 million in our western Eagle Ford acreage, from approximately $11.0 million to approximately $7.1 million in our central Eagle Ford acreage and from approximately $10.4 million to approximately $8.3 million in our eastern Eagle Ford acreage. We have also achieved a decrease in drilling days from spud to total depth over this timeframe from approximately 19 days to approximately eight days in our western Eagle Ford acreage, from approximately 19 days to approximately 14 days in our central Eagle Ford acreage and from approximately 25 days to approximately 17 days in our eastern Eagle Ford acreage. In mid-August 2013, we began drilling certain wells on our western Eagle Ford acreage from four-well batch drilled pads, which we anticipate may reduce costs by an additional $300,000 per well. Over the past 18 months, we have also refined the design of our hydraulic fracture treatments to enhance well productivity, increasing proppant volumes from approximately 1,250 pounds per foot to approximately 1,715 pounds per foot and increasing fluid volumes from approximately 19 Bbl per foot to approximately 39 Bbl per foot.

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Hedges. At August 26, 2013, we had the following hedges in place, in the form of costless collars and swaps, for the remainder of 2013 and for 2014: (i) approximately 0.8 million Bbl and 2.3 million Bbl of oil, respectively, (ii) approximately 3.3 Bcf and 8.4 Bcf of natural gas, respectively, and (iii) approximately 5.0 million and 5.1 million gallons of natural gas liquids, respectively.

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Initial Results from 40-acre and 50-acre Downspacing in the Eagle Ford. During the second quarter of 2013, we completed our first 40-acre test well, the Martin Ranch #35H, on our Martin Ranch leasehold in northeast La Salle County. On a 24-hour initial potential test following completion, the well flowed at an average rate of 464 Bbl of oil per day at 1,450 psi surface pressure on a 14/64-in choke, comparable to other recently completed wells on our Martin Ranch lease, and consistent with our practice of flowing back our newly-completed wells on smaller chokes to preserve and manage bottomhole pressure to try and improve long-term well performance and ultimate recoveries. During its first sixty days, this 40-acre offset well’s performance was in line with our expectations and was flowing at an average rate of approximately 300 Bbl of oil per day. We completed three new wells at approximately 50-acre spacing on our Sickenius lease in Karnes County in July 2013. On 24-hour initial potential tests following completion, these wells flowed at average rates of between 580 and 850 Bbl of oil per day at 2,500 to 3,000 psi surface pressure on 14/64-in chokes. As a result of the initial performance of these downspaced wells, we plan to drill 40-acre infill wells on our nearby Danysh and Pawelek leases in Karnes County beginning this fall.

Forward-Looking Statements

This Current Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. “Forward-looking statements” are statements related to future, not past, events. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as “could,” “believe,” “would,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,” “predict,” “potential,” “project” and similar expressions that are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Actual results and future events could differ materially from those anticipated in such statements, and such forward-looking statements may not prove to be accurate. These forward-looking statements involve certain risks and uncertainties, including, but not limited to, the following risks related to financial and operational performance: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; our ability to make acquisitions on economically acceptable terms; availability of sufficient capital to execute our business plan, including from future cash flows, increases in our borrowing base and otherwise; weather and environmental conditions; and other important factors which could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. For further discussions of risks and uncertainties, you should refer to Matador’s SEC filings, including the “Risk Factors” section of Matador’s most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. Matador undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after the date of this Current Report, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this Current Report. All forward-looking statements are qualified in their entirety by this cautionary statement.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.


Exhibit No.		Description

99.1		Press Release, dated September 3, 2013.

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.

INDEX TO EXHIBITS


Exhibit No.		Description

99.1		Press Release, dated September 3, 2013.