We witnessed some key themes emerging during the second-quarter earnings season, including the following: Improved drilling times, wider spread implementation of pad drilling, and prior infrastructure investments are leading to marked improvement in efficiency gains. This trend was most evident with reduced completed well costs, with gains coming from a variety of areas, including reduced spud-spud (the process of beginning to drill a well) times, lower services charges on the completion side as capacity remains loose, a move toward slick-water fracs versus gel fracs and less use of ceramic proppants.
We saw operators reduce costs in the Permian, Bakken, Eagle Ford, Marcellus and Mississippi Lime.
The end result is higher production/cash flow per dollar of capital expenditure (or capex) spending, in addition to few rigs required to drill the same number of wells.
Infrastructure constraints persist, but should improve in the second half of 2013 as new capacity comes online.
During the quarter, we saw production growth limited by infrastructure constraints, including high line pressures in the Niobrara that choked older producer wells, insufficient takeaway capacity in the Delaware basin, and lack of takeaway/compression capacity in the Marcellus. We expect some of these issues to ease in the second half as new capacity comes online in the Marcellus and Niobrara.
Penn Virginia Corporation (PVA) is up to 62,000 net acres in the Eagle Ford, after recently adding about 9,000 net acres in the play.
Penn Virginia has been testing downspacing to between 45 and 70 acres in the play, which it feels is successful and, based on this downspacing, now estimates [there may be] 750 undeveloped drilling locations in the play.
Production, when including the acquired Magnum Hunter Resources assets, was up 53% quarter over quarter, and Penn Virginia is currently running four operated rigs and participating in two non-operated rigs.
42.3 net Eagle Ford wells, not including seven net wells drilled by Magnum Hunger Resources prior to the acquisition, are forecasted to be drilled in 2013.
Penn Virginia reported second-quarter 2013 cash flow per share of $0.76 on a diluted basis, slightly below our $0.78 estimates, and second-quarter 2013 cash flow per share of $0.99 on a basic basis, in line with the Street forecast of $0.99. Second-quarter 2013 earnings per share were -$0.17, slightly below our estimate of -$0.14 and the Street at -$0.15.
Second-quarter 2013 production averaged 19.2 thousand barrels of oil equivalent (or mboe), up 21% quarter over quarter, as acquired Eagle Ford volumes aided the strong sequential growth.
However, actual production beat our 18.6 thousand barrels of oil equivalent per day estimate by 4%.
In addition to higher volumes, the acquired Eagle Ford assets improved the oil weighting from 42% in the first quarter of 2013 to 49% [in the most recent] quarter.
Despite the higher oil volumes, unit lease operating expenses fell by 12% quarter over quarter to $10.63 per barrel of oil equivalent, and lower than our $11.71 barrel of oil equivalent estimate.
Macquarie Capital (Europe)
[In the second quarter,] Royal Dutch Shell’s (RDS-A, RDS-B) financial objectives [were] maintained—on a net basis. The major targets of cash flow from operations (CFFO) of $175 billion to $200 billion and net capital expenditures of $120 billion to $130 billion from 2012-2015 are essentially unchanged. Cash flow from operations was $12.4 billion in the quarter, including a positive working capital contribution of $4 billion; over the six quarters since the beginning of 2012, Shell has generated $70 billion of cash flow from operations, which is right on the pro rata pace for the midpoint. However, that $70 billion does include $7.5 billion of positive working capital contributions.
We note that the net capital expenditure target has been maintained despite the expectation for accelerated divestitures, which amounts to raising the organic capital expenditure target.
We expect that Shell could make major decisions on natural gas infrastructure projects in North America (gas to liquids and petrochemicals) that could consume an incremental $3 billion to $5 billion of capital annually and absorb the incremental proceeds from divestitures.
Total capital expenditures in 2013 are expected to be $40 billion, which includes the $6 billion acquisition of the Repsol LNG business.
Southwest Gas (SWX) filed its most recent rate case in California last December, requesting an $11.6 million increase in margin based on a 57% common equity band and a 10.7% return on equity. It also asked for continued adjustments for annual attrition of 2.95% between 2015 and 2018.
Lastly, it proposed an infrastructure replacement mechanism, similar to what it has in Arizona and Nevada.
Rates are expected to become effective January 1, 2014. In Nevada, Southwest Gas is seeking to receive regulatory asset treatment for the accelerated replacement of $15.6 million of early vintage pipe.
It also requested an ongoing accelerated replacement program of up to $40 million for 2014 and beyond. A decision is anticipated by later this year.
Capital expenditure guidance: Capital spending this year is a bit higher than it has been in previous years at $320 million to $340 million and will somewhat hinge on the regulatory decisions on infrastructure trackers. Between 2013 and 2015, Southwest Gas anticipates spending about $1 billion.
Dividend should outpace EPS growth: Currently, the payout ratio is approximately 40%, despite a 12% increase in the dividend in February.
With the receipt of decoupling in its service territories and therefore less volatility in earnings, the company has disclosed its intent to slowly raise its dividend at a pace so that its payout ratio would be more in line with the peer average of approximately 65%.
We raise our 2014 EPS estimate to $2.98 from $2.73 on improved construction results and lower interest expense. We raise our price target to $48.
Paul S. Forward, CFA
Natural Resource Partners’ (NRP) second-quarter 2013 coal volumes of 14.9 million tons were ahead of our 13.3 million ton estimate, but average royalty per ton of $3.91 fell short our $4.10 estimate due to weaker pricing. The net result was second-quarter 2013 coal royalty revenues of $58.2 million, which surpassed our $54.5 million estimate due to the higher volumes.
Relative to first-quarter 2013 results, coal royalty production rose 8% (from 13.8 million tons in Q1’13; higher in all regions except Northern Appalachia, which was down slightly) and coal royalty revenues rose 7% (from $54.4 million in Q1’13) due to the quarter-over-quarter increase in volumes.
Second-quarter 2013 revenues other than coal royalties totaled $28.6 million, below our estimate of $35.4 million (and first-quarter 2013’s $39.9 million) due to lower-than-expected minimums recognized as revenues and override royalties/other revenues.
We attribute the earnings per share miss to these items, along with somewhat higher depletion, depreciation and amortization, or DD&A ($17.4 million versus our $14.8 million estimate), and selling, general and administrative expense ($8.9 million vs. our $7.5 million estimate) than we had been modeling.
OCI Wyoming: Natural Resource Partners recognized $7.9 million in revenue associated with the OCI acquisition in the second quarter of 2013 ($14.9 million in the first half of 2013) and received a total of $26.9 million in OCI distributions in the first half of 2013.
Natural Resource Partners said the partnership received an additional $46.0 million in dividends and distributions in July, including a $44.8 million special distribution due to a restructuring of OCI Wyoming. This is being used to pay for the previously announced $35 million agreement to purchase oil and gas assets in the Bakken, along with debt pay-down.